Evolve Transition Infrastructure (SNMP) 10-K 5 Mar 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Mar. 02, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	spp
Entity Registrant Name	Sanchez Production Partners LLC
Entity Central Index Key	1362705
Current Fiscal Year End Date	-19
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		28,777,014
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Public Float			$51,634,210

Consolidated_Statements_Of_Ope

Consolidated Statements Of Operations (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Revenues
Natural gas sales	$34,458	$23,129
Oil sales	40,337	20,436
Natural gas liquid sales	2,477	512
Total revenues	77,272	44,077
Operating expenses:
Lease operating expenses	21,012	18,858
Cost of sales	1,487	1,455
Production taxes	3,200	2,601
General and administrative	16,499	22,214
Loss on sale of assets	223	4
Depreciation, depletion and amortization	17,533	18,972
Asset impairments (See Note 7)	5,424	2,357
Accretion expense	604	519
Total operating expenses	65,982	66,980
Other expense / (income)
Interest expense	2,076	3,150
Other income	-289	-196
Total other expenses	1,787	2,954
Total expenses	67,769	69,934
Income (loss) from continuing operations	9,503	-25,857
Loss from discontinued operations		-2,686
Net income (loss)	9,503	-28,543
Weighted Average Units Outstanding
Weighted Average Units Outstanding - Basic	29,194,847	26,143,719
Weighted Average Units Outstanding - Diluted	29,295,672	26,143,719
Distributions declared and paid per unit
Common Class A [Member]
Other expense / (income)
Income (loss) from continuing operations	190	-517
Loss from discontinued operations		-53
Net income (loss)	190	-570
Income (loss) from continuing operations per unit
Continuing operations - Basic and diluted	$0.25	($0.55)
Loss from discontinued operations per unit
Discontinued operations per unit - Basic and diluted		($0.06)
Net income (loss) per unit
Net income (loss) per unit - Basic and diluted	$0.25	($0.61)
Weighted Average Units Outstanding
Weighted Average Units Outstanding - Basic	763,261	933,613
Weighted Average Units Outstanding - Diluted	763,261	933,613
Common Class B [Member]
Other expense / (income)
Income (loss) from continuing operations	9,313	-25,340
Loss from discontinued operations		-2,633
Net income (loss)	$9,313	($27,973)
Income (loss) from continuing operations per unit
Continuing operations - Basic and diluted	$0.33	($1.01)
Loss from discontinued operations per unit
Discontinued operations per unit - Basic and diluted		($0.10)
Net income (loss) per unit
Net income (loss) per unit - Basic and diluted	$0.33	($1.11)
Weighted Average Units Outstanding
Weighted Average Units Outstanding - Basic	28,431,586	25,210,106
Weighted Average Units Outstanding - Diluted	28,532,411	25,210,106

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets
Cash and cash equivalents	$4,238	$4,894
Restricted cash (See Note 1)	1,748
Accounts receivable	5,217	6,678
Prepaid expenses	1,783	2,547
Risk management assets (See Note 5)	14,671	9,141
Total current assets	27,657	23,260
Oil and natural gas properties (See Note 7)
Oil and natural gas properties, equipment and facilities	651,493	639,156
Material and supplies	1,056	1,054
Less accumulated depreciation, depletion, amortization, and impairments	-517,239	-495,215
Net oil and natural gas properties	135,310	144,995
Other assets
Debt issue costs (net of accumulated amortization of $9,138 and $9,003, respectively)	689	824
Risk management assets (See Note 5)	8,158	1,461
Restricted cash		1,748
Other non-current assets	1,790	2,245
Total assets	173,604	174,533
Current liabilities
Accounts payable	35	12
Accrued liabilities	6,081	12,763
Royalty payable	1,134	1,242
Total current liabilities	7,250	14,017
Other liabilities
Asset retirement obligation	17,031	9,513
Other non-current liabilities		1,398
Debt (See Note 6)	42,500	50,700
Total other liabilities	59,531	61,611
Total liabilities	66,781	75,628
Commitments and contingencies (See Note 10)
Members' equity
Total members' equity	106,823	98,905
Total liabilities and members' equity	173,604	174,533
Common Class A [Member]
Members' equity
Limited partners' capital account	1,930	2,591
Common Class B [Member]
Members' equity
Limited partners' capital account	$104,893	$96,314

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
Debt issue costs, accumulated amortization	$9,138	$9,003
Common Class A [Member]
Share units authorized	484,505	1,615,017
Share units issued	484,505	1,615,017
Shares units outstanding	484,505	1,615,017
Common Class B [Member]
Share units authorized	28,903,734	28,848,785
Share units issued	28,792,584	28,462,185
Shares units outstanding	28,792,584	28,462,185

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net income (loss)	$9,503	($28,543)
Adjustments to reconcile net income (loss) to cash provided by operating activities
Depreciation, depletion and amortization	17,533	18,972
Asset impairments (See Note 7)	5,424	2,357
Amortization of debt issuance costs	271	1,289
Accretion expense	604	519
Equity earnings in affiliate	-216	-271
Loss from disposition of property and equipment	223	4
Bad debt expense	94	44
Mark-to-market on derivatives:
Total gains	-19,855	1,551
Cash settlements	7,626	12,082
Unit-based compensation programs	1,298	1,049
Discontinued operations		2,686
Changes in Assets and Liabilities:
(Increase) decrease in accounts receivable	1,370	-1,106
(Increase) decrease in prepaid expenses	764	-1,238
Decrease in other assets	2	8
Increase (decrease) in accounts payable	23	-468
Increase (decrease) in accrued and other liabilities	-7,557	5,383
Decrease in royalty payable	-108	-176
Net cash provided by continuing operations	16,999	14,142
Net cash provided by discontinued operations		1,062
Net cash provided by operating activities	16,999	15,204
Cash flows from investing activities:
Cash paid for acquisitions, net of cash acquired	-1,351	-20,221
Development of natural gas properties	-5,865	-15,694
Proceeds from sale of property and equipment	485	58,987
Increase in cash held for escrow		-1,148
Distributions from equity affiliate	295	245
Net cash provided by (used in) investing activities	-6,436	22,169
Cash flows from financing activities:
Proceeds from issuance of debt	5,750	16,894
Repayment of debt	-13,950	-50,194
Repurchase of Class A, Class C and Class D interests	-2,468
Units tendered by employees for tax withholdings	-415	-185
Debt issue costs	-136	-953
Net cash used in financing activities	-11,219	-34,438
Net increase (decrease) in cash	-656	2,935
Cash and cash equivalents, beginning of period	4,894	1,959
Cash and cash equivalents, end of period	4,238	4,894
Supplemental disclosures of cash flow information:
Change in accrued capital expenditures	512	1,674
Cash paid during the period for interest	-1,841	-1,881
Cash paid during the period for income taxes	($73)	($75)

Consolidated_Statements_Of_Cha

Consolidated Statements Of Changes In Members' Equity (USD $)	Common Class A [Member]	Common Class B [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Total
In Thousands, except Share data
Beginning Balance at Dec. 31, 2012	$2,326	$113,940		$116,266
Beginning Balance (in shares) at Dec. 31, 2012	483,418	23,687,507
Distributions
Units tendered by employees for tax withholding (in shares)	-2,853	-139,810
Units tendered by employees for tax withholding, cost	-4	-181		-185
Unit-based compensation programs (in shares)	3,940	190,081
Unit-based compensation programs	21	1,028		1,049
Unit issued for acquisition of properties (in shares)	1,130,512	4,724,407
Unit issued for acquisition of properties	818	9,500		10,318
Net income (loss)	-570	-27,973		-28,543
Ending Balance at Dec. 31, 2013	2,591	96,314		98,905
Ending Balance (in shares) at Dec. 31, 2013	1,615,017	28,462,185
Distributions
Units tendered by employees for tax withholding (in shares)		-160,182
Units tendered by employees for tax withholding, cost		-415		-415
Unit-based compensation programs (in shares)		490,581
Unit-based compensation programs		1,298		1,298
Cancellation of units (in shares) (See Note 9)	-1,130,512
Cancellation of units (See Note 9)	-851	-1,617		-2,468
Net income (loss)	190	9,313		9,503
Ending Balance at Dec. 31, 2014	$1,930	$104,893		$106,823
Ending Balance (in shares) at Dec. 31, 2014	484,505	28,792,584

Summary_Of_Significant_Account

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Summary Of Significant Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	Organization
	Sanchez Production Partners LLC (SPP, we, us, our or the Company) (formerly Constellation Energy Partners LLC) was organized as a limited liability company on February 7, 2005, under the laws of the State of Delaware. We completed our initial public offering on November 20, 2006, and currently trade on the NYSE MKT LLC (NYSE MKT) under the symbol “SPP”.  We are currently focused on the acquisition, development and production of oil and natural gas properties and other integrated assets.  Our proved reserves are currently located in the Cherokee Basin in Oklahoma and Kansas, the Woodford Shale in the Arkoma Basin in Oklahoma, the Central Kansas Uplift in Kansas and in Texas and Louisiana.
	Through subsidiaries Sanchez Oil & Gas Corporation (SOG) owns a portion of our outstanding units. As of December 31, 2014, Sanchez Energy Partners I, LP (SEP I), a subsidiary of SOG, owned 484,505, or 100%, of our Class A units and 5,364,196, or 18.6%, of our Class B common units.
	On October 3, 2014, Constellation Energy Partners LLC (CEP) changed its name to Sanchez Production Partners LLC.  The name change was effected pursuant to Section 18-202 of the Delaware Limited Liability Company Act (the DLLCA) by filing a Fourth Certificate of Amendment to Certificate of Formation with the Secretary of State of the State of Delaware.  Under the DLLCA and the Company’s Second Amended and Restated Operating Agreement, as amended, the name change did not require approval of the Company’s unitholders.
	On August 25, 2014, our board of managers approved a plan of conversion providing for the conversion of the Company from a limited liability company organized under the laws of the State of Delaware to a limited partnership organized under the laws of the State of Delaware.  Pursuant to the plan of conversion, at the effective time of the conversion, each outstanding common unit of the Company will be converted onto one unit of Sanchez Production Partners LP (Sanchez LP), the outstanding Class A units of the Company will be converted into common units of Sanchez LP in a number equal to 2% of the Sanchez LP common units outstanding immediately after the conversion (after taking into account the conversion of the Class A units) and the outstanding Class Z unit will be cancelled.  In addition, a SOG-related company will become the general partner of Sanchez LP, and incentive distribution rights will be issued by Sanchez LP to another SOG-related company.  On January 30, 2015, the Company received a Notice of Effectiveness from the SEC regarding its registration statement on Form S-4 with respect to the common units of Sanchez LP to be issued to the Company’s common unitholders and the Class A unitholder in connection with the conversion.  A special meeting of the Company’s unitholders will be held on March 6, 2015 to vote on the plan of conversion and an amendment and restatement of the Constellation Energy Partners LLC 2009 Omnibus Incentive Compensation Plan as the Sanchez Production Partners LP Long-Term Incentive Plan.
	On June 26, 2014, we settled the lawsuit brought by Constellation Energy Partners Holdings, LLC (CEPH), a subsidiary of Exelon Corporation, against us in the Court of Chancery of the State of Delaware (the Exelon Litigation).  In conjunction with the settlement, we paid CEPH $1.65 million in exchange for all of the Class C management incentive interests and Class D interests held by CEPH, which were all of such interests issued by SPP.  Effective with the acquisition of these interests from CEPH, we cancelled the Class C management incentive interests and Class D interests.
	On May 8, 2014, the Company and SP Holdings, LLC (the Manager), a SOG-related company, entered into a Shared Services Agreement (the Services Agreement) pursuant to which, as of July 1, 2014, the Manager provides services that the Company requires to operate its business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, professionals and acquisition, disposition and financing services.
	Basis of Presentation
	Accounting policies used by us conform to accounting principles generally accepted in the United States of America. The accompanying financial statements include the accounts of us and our wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. We operate our oil and natural gas properties as one business segment: the exploration, development and production of oil and natural gas. Our management evaluates performance based on one business segment as there are not different economic environments within the operation of our oil and natural gas properties.
	Use of Estimates
	Estimates and assumptions are made when preparing financial statements under accounting principles generally accepted in the United States of America. These estimates and assumptions affect various matters, including:
	•reported amounts of revenue and expenses in the Consolidated Statements of Operations during the reported periods,
	•reported amounts of assets and liabilities in the Consolidated Balance Sheets at the dates of the financial statements,
	•disclosure of quantities of reserves and use of those reserve quantities for depreciation, depletion and amortization, and
	•disclosure of contingent assets and liabilities at the date of the financial statements.
	These estimates involve judgments with respect to numerous factors that are difficult to predict and are beyond management’s control.  As a result, changes in facts and circumstances or additional information may result in revised estimates or actual amounts may materially differ from these amounts.
	Reclassifications
	Certain reclassifications have been made to the prior periods to conform to the current period presentation.  These reclassifications had no effect on total assets, total liabilities, total unitholders’ equity, net income or net cash provided by or used in operating, investing or financing activities.
	Discontinued Operations
	In February 2013, we sold all of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama.  The related results of operations and cash flows have been classified as discontinued operations in the consolidated statements of operations, balance sheets, statements of cash flows and consolidated financial information.  Unless otherwise indicated, information presented in the Notes to Consolidated Financial Statements relates only to the Company’s continuing operations.  Information related to discontinued operations is included in Note 2. Discontinued Operations.
	Cash and Cash Equivalents
	All highly liquid investments with original maturities of three months or less are considered cash equivalents. Checks-in-transit are included in accounts payable in our consolidated balance sheets.  There were no checks-in-transit as of December 31, 2014 and 2013.
	Restricted Cash
	Restricted cash at December 31, 2014 and 2013 of $1.7 million was held in escrow in relation to the sale of the Robinson’s Bend Field assets and related to litigation involving one of our service providers.
	Concentration of Credit Risk and Accounts Receivable
	Financial instruments that potentially subject us to a concentration of credit risk consist of cash and cash equivalents, accounts receivable and derivative financial instruments. We place our cash with high credit quality financial institutions. We place our derivative financial instruments with financial institutions that participate in our reserve-based credit facility and maintain an investment grade credit rating. Substantially all of our accounts receivables are due from purchasers of oil and natural gas. These sales are generally unsecured and, in some cases, may carry a parent guarantee. As we generally have fewer than 10 large customers for our oil and natural gas sales, we routinely assess the financial strength of our customers. Bad debt expense is recognized on an account-by-account review and when recovery is not probable. Our allowance for doubtful accounts was $0.2 million during 2014 and less than $0.1 million in 2013. We have no off-balance-sheet credit exposure related to our operations or customers.
	For the year ended December 31, 2014, five customers accounted for approximately 33%,  30%,  16%,  14% and 7% of our sales revenues. For the year ended December 31, 2013, five customers accounted for approximately 22%,  20%,  17%,  14% and 8% of our sales revenues.
	Oil and Natural Gas Properties
	Oil and Natural Gas Properties
	We follow the successful efforts method of accounting for our oil and natural gas exploration, development and production activities. Leasehold acquisition costs, property acquisition and the costs of development of proved areas are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred.
	Accounting rules require that we price our oil and natural gas proved reserves at the preceding twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. Such SEC-required prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Our proved reserve estimates exclude the effect of any derivatives we have in place.
	Depreciation, Depletion and Amortization
	Depreciation and depletion of producing oil and natural gas properties is recorded at the field level, based on the units-of-production method. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (including wells and related equipment and facilities) are amortized on the basis of proved developed reserves. It has been our historical practice to use our year-end reserve report to adjust our depreciation, depletion, and amortization expense for the fourth quarter. Depreciation, depletion, and amortization expense is calculated using year-end reserve reports based on the SEC-required price. As more fully described in Note 15, proved reserves estimates are subject to future revisions when additional information becomes available.
	Asset Retirement Obligation
	As described in Note 11, estimated asset retirement costs are recognized when the asset is acquired or placed in service, and are amortized over proved developed reserves using the units-of-production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.
	Unsuccessful Wells
	Geological, geophysical and dry hole costs on oil and natural gas properties relating to unsuccessful exploratory wells are charged to expense as incurred.
	Impairment
	Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. The cash flow estimates are based upon third party reserve reports using future expected oil and natural gas prices adjusted for basis differentials. Cash flow estimates for the impairment testing exclude derivative instruments. Refer to Note 7 for additional information.
	Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that we expect to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period. The valuation allowances are reviewed at least annually.
	Property acquisition costs are capitalized when incurred.
	Support Equipment and Facilities
	Support equipment and facilities consist of certain of our water treatment facilities, gathering lines, roads, pipelines and other various support equipment. Items are capitalized when acquired and depreciated using the straight-line method over the useful life of the assets.
	Materials and Supplies
	Materials and supplies consist of well equipment, parts and supplies. They are valued at the lower of cost or market, using either the specific identification or first-in first-out method, depending on the inventory type. Materials and supplies are capitalized as used in the development or support of our oil and natural gas properties.
	Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
	Our estimate of proved reserves is based on the quantities of oil, natural gas and natural gas liquids that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Proved reserves are calculated based on various factors, including consideration of an independent reserve engineers’ report on proved reserves and an economic evaluation of all of our properties on a well-by-well basis. The process used to complete the estimates of proved reserves at December 31, 2014 and 2013 is described in detail in Note 15.
	Reserves and their relation to estimated future net cash flows impact depletion and impairment calculations. As a result, adjustments to depletion and impairments are made concurrently with changes to reserve estimates. The accuracy of reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.
	Proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.
	Derivatives and Hedging Activities
	We use derivative financial instruments to achieve a more predictable cash flow from our oil and natural gas production by reducing our exposure to price fluctuations. Additionally, we use derivative financial instruments in the form of interest rate swaps to mitigate interest rate exposure on our borrowings under our reserve-based credit facility.
	We account for all our open derivatives as mark-to-market activities. All derivative instruments are recorded in the consolidated balance sheet as either an asset or a liability measured at fair value with changes in fair value recognized in earnings. All of our open derivatives are effective as economic hedges of our commodity price or interest rate exposure. These contracts are accounted for using the mark-to-market accounting method. Using this method, the contracts are carried at their fair value on our consolidated balance sheets under the captions “Risk management assets” and “Risk management liabilities.” We recognize all unrealized and realized gains and losses related to these contracts on our consolidated statements of operations under the caption “Oil sales” or “Natural gas sales” and settled interest rate swaps as “Interest expense.”
	Revenue Recognition
	Sales are recognized when oil, natural gas and natural gas liquids have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Oil, natural gas and natural gas liquids are generally sold on a monthly basis. Most of the contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a specific tank battery, gathering or transmission line, quality of oil, natural gas and natural gas liquids, and prevailing supply and demand conditions, so that the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies. As a result, revenues from the sale of oil, natural gas and natural gas liquids will suffer if market prices decline and benefit if they increase. We believe that the pricing provisions of our oil, natural gas and natural gas liquids contracts are customary in the industry.
	Gas imbalances occur when sales are more or less than the entitled ownership percentage of total gas production. We use the entitlements method when accounting for gas imbalances. Any amount received in excess is treated as a liability. If less than the entitled share of the production is received, the excess is recorded as a receivable.  There was only a minimal gas imbalance position on one of our wells in the Mid-continent region at December 31, 2014. There were no gas imbalance positions at December 31, 2013.
	Income Taxes
	SPP and each of its wholly-owned subsidiary LLCs are treated as a partnership for federal and state income tax purposes.  All of our taxable income or loss, which may differ considerably from net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our members. As such, no federal income tax for these entities has been provided for in the accompanying financial statements. SPP is subject to franchise tax obligations in Kansas and Texas and state tax obligations in Alabama and Oklahoma. SPP also has informational filing requirements in Georgia, Indiana, Louisiana, Maine, Missouri, New Jersey, New York, Oregon, Pennsylvania, and West Virginia because we have resident unitholders in these states.
	Our wholly-owned subsidiary, CEP Services Company, Inc. is a taxable entity. For the years ended December 31, 2014, and 2013, the current and deferred income taxes for the entity were immaterial. The entity has no material deferred tax assets or liabilities.
	Earnings per Unit
	Basic earnings per unit (EPU) is computed from the two-class method by dividing net income (loss) attributable to unitholders by the weighted average number of units outstanding during each period.  To determine net income (loss) allocated to each class of ownership (Class A and Class B), we first allocate net income (loss) in accordance with the amount of distributions made for the period by each class, if any.  The remaining net income (loss) is allocated to each class in proportion to the class weighted average number of units outstanding for the period, as compared to the weighted average number of units for all classes for the period.
	As of December 31, 2014 and 2013, we had unvested restricted common units outstanding, which were considered dilutive securities.  These units will be considered in the diluted weighted average common units outstanding number in periods of net income.  In periods of net losses, these units are excluded for the diluted weighted average common unit outstanding number as they are not participating securities.
	The following table presents our calculation of basic and diluted units outstanding for the periods indicated:
		Year Ended December 31,
	2014		2013
Weighted average units outstanding during period:
Class A units - Basic		763,261		933,613
Class B Common units - Basic		28,431,586		25,210,106
		29,194,847		26,143,719
Weighted average units outstanding during period:
Class A units - Diluted		763,261		933,613
Class B Common units - Diluted		28,532,411		25,210,106
		29,295,672		26,143,719
At December 31, 2014, we had 100,825 Class B common units that were restricted unvested common units granted and outstanding.  These units were included in the diluted weighted average common units outstanding number since we recognized net income for the period.  At December 31, 2013, we had 380,327 Class B common units that were restricted unvested common units granted and outstanding.  These units were excluded from the diluted weighted average common units outstanding number since we recognized a net loss for the year.
The following table presents our basic and diluted income per unit for the year ended December 31, 2014 (in thousands, except for per unit amounts):
	Total		Class A Units		Class B Units
Income from continuing operations	$	9,503
Distributions		-	$	-	$	-
Assumed allocation of income from continuing operations		9,503		190		9,313
Discontinued operations		-		-		-
Assumed net income to be allocated	$	9,503	$	190	$	9,313
Basic and diluted income from continuing operations per unit			$	0.25	$	0.33
Basic and diluted income from discontinued operations per unit			$	-	$	-
Basic and diluted income per unit			$	0.25	$	0.33
The following table presents our basic and diluted income per unit for the year ended December 31, 2013 (in thousands, except for per unit amounts):
	Total		Class A Units		Class B Units
Loss from continuing operations	$	-25,857
Distributions		-	$	-	$	-
Assumed allocation of loss from continuing operations		-25,857		-517		-25,340
Discontinued operations		-2,686		-53		-2,633
Assumed net loss to be allocated	$	-28,543	$	-570	$	-27,973
Basic and diluted loss from continuing operations per unit			$	-0.55	$	-1.01
Basic and diluted loss from discontinued operations per unit			$	-0.06	$	-0.1
Basic and diluted loss per unit			$	-0.61	$	-1.11
Environmental Cost
We record environmental liabilities at their undiscounted amounts on our balance sheets in other current and long-term liabilities when our environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Federal Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods.  At December 31, 2014, we had no environmental liabilities recorded, as no liabilities were deemed necessary.
Unit-Based Compensation
We record compensation expense for all equity grants issued under the Long-Term Incentive Program and the 2009 Omnibus Incentive Compensation Plan based on the fair value at the grant date, recognized over the vesting period.
Other Contingencies
We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates it is both probable that an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. Funds spent to remedy these contingencies are charged against the associated reserve, if one exists, or expensed. When a range of probable loss can be estimated, we accrue the most likely amount or at least the minimum of the range of probable loss.
Recent Pronouncements and Accounting Changes
From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (the FASB), which are adopted by us as of the specified effective date.  Unless otherwise discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on our consolidated financial statements upon adoption.
In April 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.  This guidance changes the definition of a discontinued operation to include only those disposals of components of an entity that represent a strategic shift that has or will have a major effect on an entity’s operations and financial results.  This guidance is effective prospectively for fiscal years beginning after December 15, 2014.  The effects of this accounting standard on our financial position, results of operations and cash flows will not be material.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606).  This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance.  This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized.  The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services.  The new guidance may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the date of initial application.  We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material.
In August 2014, the FASB issued ASU No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.  This guidance creates a new subtopic ASC 205-40, “Presentation of Financial Statements – Going Concern,” and provides guidance about management’s responsibility to evaluate whether there is a substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures.  The requirements in this guidance are effective for the annual period ending after December 15, 2016, which is fiscal 2017 for us, and for annual and interim periods thereafter.  Early application is permitted.  We acknowledge this new guidance and will comply with the disclosure requirements, if applicable, beginning in fiscal 2017.  The adoption of this guidance will have no material impact on our financial position, results of operations or cash flows.

Discontinued_Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2014
Discontinued Operations [Abstract]
Discontinued Operations	2. DISCONTINUED OPERATIONS
	Sale of Robinson’s Bend Field Assets
	On February 28, 2013, we sold all of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama for $63.0 million, subject to closing adjustments that amounted to approximately $4.0 million.  We recorded a loss on the sale of approximately $3.1 million in the three months ended March 31, 2013.  The sale of the Robinson’s Bend Field assets was initiated to provide the financial flexibility necessary to support our efforts for pursuing opportunities and further developing our properties in the Mid-Continent region, as well as reducing our outstanding debt.
	The following amounts relating to the Robinson’s Bend Field assets have been reported as discontinued operations in the consolidated statements of operations in the year ending December 31, 2013 (in thousands):
		Year Ended
		31-Dec-13
	Revenues	$	2,304
	Loss from discontinued operations	$	-2,686
	See Note 1 for information regarding earnings per unit, including earnings per unit data relating to income from discontinued operations, which includes loss on sale of discontinued operations in 2013.
	There were no major classes of assets and liabilities components of discontinued operations at December 31, 2013.
	There were no significant divestitures of oil and natural gas properties during the year ended December 31, 2014.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2014
Acquisitions [Abstract]
Acquisitions	3. ACQUISITIONS
	Acquisition of Oil, Natural Gas and Natural Gas Liquids Properties from SEP I
	On August 9, 2013, we acquired oil, natural gas and natural gas liquids assets in Texas and Louisiana from SEP I for a purchase price of $30.4 million.  In conjunction with the acquisitions, SEP I received $20.1 million in cash; 1,130,512 Class A units and 4,724,407 Class B units.  The cash portion of the transaction was financed with cash on hand and a borrowing of $16.7 million under our reserve-based credit facility.
	The acquired assets included 67 producing wells in Texas and Louisiana.  The primary factors considered by management in acquiring the SEP I properties included the belief that these wells provide an opportunity to significantly increase our reserves, production volumes and drilling portfolio, while maintaining our focus of increasing our oil-weighted assets.  The SEP I properties also provide us with access to exploitation and development potential.
	The following allocation of the purchase price is based on information that was available to management at the time these consolidated financial statements were prepared and takes into account current market conditions and estimated market prices for oil and natural gas.
	The following table summarizes the values of assets acquired and liabilities assumed effective August 1, 2013 (in thousands):
	Oil and natural gas properties, equipment and facilities	$	31,497
	Asset retirement obligation		-1,088
	Net assets acquired	$	30,409
	We have accounted for our acquisition of oil and natural gas properties using the purchase method of accounting for business combinations, and therefore, we have estimated the fair value of the assets acquired and the liabilities assumed as of the acquisition date.  The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs.  The fair value of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount.  Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) estimated future cash flows and (v) a market-based weighted cost of capital rate.  These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.
	Results of Operations and Pro Forma Information
	The following table sets forth revenues and lease operating expenses attributable to the SEP I properties acquired (in thousands):
		Twelve Months Ended
		December 31,
		2013
	Revenue	$	15,782
	Lease Operating Expenses	$	3,047
	We have determined that the presentation of net income attributable to the SEP I properties is impracticable due to the integration of the related operations upon acquisition.
	The following supplemental pro forma information presents consolidated results of operations as if the acquisition of the SEP I properties had occurred on January 1, 2013.  The supplemental unaudited pro forma information was derived from a) our historical consolidated statements of operations and b) the statements of operations of SEP I.  This information does not purport to be indicative of results of operations that would have occurred had the acquisition occurred on January 1, 2013, nor is such information indicative of any expected future results of operations.
		Pro Forma
		Twelve Months Ended
		December 31,
	(In thousands)	2013
	Revenue	$	56,841
	Income (loss) from continuing operations	$	-18,514
	Discontinued operations	$	-2,686
	Net Loss	$	-21,200
	Income (loss) from continuing operations per unit
	Class A units - Basic and diluted	$	-0.23
	Class B units - Basic and diluted	$	-0.65
	Discontinued operations per unit
	Class A units - Basic and diluted	$	-0.03
	Class B units - Basic and diluted	$	-0.09
	Net loss per unit
	Class A units - Basic and diluted	$	-0.26
	Class B units - Basic and diluted	$	-0.74
	Weighted average units outstanding
	Class A units - Basic and diluted		1,615,103
	Class B units - Basic and diluted		28,057,592
	Acquisition of Oil and Natural Gas Properties
	On April 9, 2014, we acquired a 20% working interest in nine producing wells and other assets for $1.4 million.  The assets are located in LaSalle Parish, Louisiana and are operated by SOG.  This purchase became effective May 1, 2014.  The impact of the acquisition of these properties was not material to our consolidated financial statements, so no pro forma information for this acquisition is provided.

Fair_Value_Messurements

Fair Value Messurements	12 Months Ended
	Dec. 31, 2014
Fair Value Measurements [Abstract]
Fair Value Measurements	4. FAIR VALUE MEASUREMENTS
	We measure certain financial assets and liabilities at fair value.  Fair value is defined as an “exit price” which represents the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of  the measurement date.  As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in valuing an asset or liability.  The accounting guidance also requires the use of valuation techniques to measure fair value that maximize the use of observable inputs and minimize the use of unobservable inputs.  As a basis for considering such assumptions and inputs, a fair value hierarchy has been established which identifies and prioritizes three levels of inputs to be used in measuring fair value.
	The three levels of the fair value hierarchy are as follows:
	Level 1 – Observable inputs such as quoted prices (unadjusted) in active markets for identical assets or liabilities.
	Level 2 – Inputs other than the quoted prices in active markets that are observable either directly or indirectly, including: quoted prices for similar assets and liabilities in active markets; quoted prices for identical or similar assets and liabilities in markets that are not active or other inputs that are observable or can be corroborated by observable market data.
	Level 3 – Unobservable inputs that are supported by little or no market data and require the reporting entity to develop its own assumptions.
	As required by accounting guidance for fair value measurements, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
	The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 (in thousands):
		Fair Value Measurements at December 31, 2014
		Quoted Prices in		Significant other
		Active Markets for		Observable		Significant
		Identical Assets		Inputs		Unobservable Inputs		Netting Cash and		Fair Value at
		(Level 1)		(Level 2)		(Level 3)		Collateral		31-Dec-14
	Risk Mgmt Assets	$	—	$	22,919	$	—	$	-90	$	22,829
	Risk Mgmt Liabilities		—		-90		—		90		—
	Total Net Assets and Liabilities	$	—	$	22,829	$	—	$	—	$	22,829
	The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013 (in thousands):
		Fair Value Measurements at December 31, 2013
		Quoted Prices in		Significant other
		Active Markets for		Observable		Significant
		Identical Assets		Inputs		Unobservable Inputs		Netting Cash and		Fair Value at
		(Level 1)		(Level 2)		(Level 3)		Collateral		31-Dec-13
	Risk Mgmt Assets	$	—	$	11,577	$	—	$	-975	$	10,602
	Risk Mgmt Liabilities		—		-975		—		975		—
	Total Net Assets and Liabilities	$	—	$	10,602	$	—	$	—	$	10,602
	As of December 31, 2014, the estimated fair value of cash and cash equivalents, accounts receivable, other current assets and current liabilities approximated their carrying value due to their short-term nature.
	Fair Value of Financial Instruments
	Fair value guidance requires certain fair value disclosures, such as those on our debt and derivatives, to be presented in both interim and annual reports.  The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below.
	Reserve-Based Credit Facility – We believe that the carrying value of long-term debt for our reserve-based credit facility approximates its fair value because the interest rates on the debt approximate market interest rates for debt with similar terms.  The debt is classified as a Level 2 input in the fair value hierarchy and represents the amount at which the instrument could be valued in an exchange during a current transaction between willing parties.  Our reserve-based credit facility is discussed further in Note 6.
	Derivative Instruments – The income valuation approach, which involves discounting estimated cash flows, is primarily used to determine recurring fair value measurements of our derivative instruments classified as level 2 inputs.  Our commodity derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of oil and natural gas prices and an appropriate discount rate.  Our interest rate derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of the LIBOR interest rates and an appropriate discount rate.  We prioritize the use of the highest level inputs available in determining fair value such that fair value measurements are determined using the highest and best use as determined by market participants and the assumptions that they would use in determining fair value.

Derivative_And_Financial_Instr

Derivative And Financial Instruments	12 Months Ended
	Dec. 31, 2014
Derivative And Financial Instruments [Abstract]
Derivative And Financial Instruments	5. DERIVATIVE AND FINANCIAL INSTRUMENTS
	To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we periodically enter into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions that fix or modify the future prices to be realized.  These transactions are normally price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty.  These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations.  It is never our intention to enter into derivative contracts for speculative trading purposes.
	Under ASC Topic 815, “Derivatives and Hedging,” all derivative instruments are recorded on the consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date.  We will net derivative assets and liabilities for counterparties where we have a legal right of offset.  Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met.  We have elected to designate only a portion of our current derivative contracts as hedges;  however, changes in the fair value of all of our derivative instruments are recognized in earnings and included as realized and unrealized gains (losses) on derivative instruments in the consolidated statements of operations.
	As of December 31, 2014, we had the following derivative contracts in place for the periods indicated, all of which are accounted for as mark-to-market activities:
	MTM Fixed Price Swaps – NYMEX (Henry Hub)
		For the quarter ended (in MMBtu)
		March 31,					June 30,				September 30,			December 31,			Total
				Average					Average			Average			Average			Average
		Volume		Price			Volume		Price		Volume	Price		Volume	Price		Volume	Price
	2015	1,215,420		$	4.25		1,153,487		$	4.25	1,096,023	$	4.26	1,050,219	$	4.26	4,515,149	$	4.26
	2016	1,010,633		$	4.21		967,290		$	4.21	923,541	$	4.21	893,568	$	4.22	3,795,032	$	4.21
																	8,310,181
	MTM Fixed Price Basis Swaps – West Texas Intermediate (WTI)
		For the quarter ended (in Bbls)
		March 31,					June 30,				September 30,			December 31,			Total
				Average					Average			Average			Average			Average
		Volume		Price			Volume		Price		Volume	Price		Volume	Price		Volume	Price
	2015	69,479		$	90.99		66,183		$	91.02	63,025	$	91.05	60,143	$	91.09	258,830	$	91.04
	2016	57,420		$	85.64		54,879		$	85.64	52,474	$	85.64	50,197	$	85.64	214,970	$	85.64
																	473,800
	The table below outlines the classification of our derivative financial instruments on the consolidated balance sheets (in thousands):
					Fair Value of Asset/(Liability)
			Location of Asset/(Liability)		On Balance Sheet
	Derivative Type		On Balance Sheet		31-Dec-14			31-Dec-13
	Commodity – MTM		Risk management assets - current		$	14,698		$	10,043
	Commodity – MTM		Risk management assets  - non-current			8,221			1,534
			Total gross assets			22,919			11,577
	Commodity – MTM		Risk management assets – current			-27			-903
	Commodity – MTM		Risk management assets – non-current			-63			-72
			Total gross liabilities			-90			-975
			Total net assets and liabilities		$	22,829		$	10,602
	The effect of derivative instruments on our consolidated statements of operations was as follows (in thousands):
					Amount of Gain/(Loss) in Income
			Location of Gain/(Loss)		For the Year Ended December 31,
	Derivative Type		in Income		2014			2013
	Commodity – MTM		Oil and natural gas sales		$	19,854		$	-1,486
	Interest Rate – MTM		Interest expense			-			-65
			Total		$	19,854		$	-1,551
	Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently with two counterparties.  We generally execute commodity derivative instruments under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty.  If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election.
	We monitor the creditworthiness of our counterparties; however, we are not able to predict sudden changes in counterparties’ creditworthiness.  In addition, if such changes are sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk.  Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement.  Should one of our counterparties not perform, we may not realize the benefit of some of our derivative instruments with lower commodity prices and my incur losses. We include a measure of counterparty credit risk in our estimates of the fair values of the derivative instruments in an asset position.
	We currently use our reserve-based credit facility to provide credit support for our derivative transactions.  As a result, we do not post cash collateral with our counterparties, and have minimal non-performance credit risk on our liabilities with our counterparties.  We utilize observable market data for credit default swaps to assess the impact of non-performance credit risk when evaluating our net assets from counterparties.  At December 31, 2014 and 2013, the impact of non-performance credit risk on the valuation of our net assets from counterparties was not significant
	Hedge Liquidation, Repositioning and Novation
	In connection with the sale of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama, we liquidated 395,218 MMbtu of NYMEX swaps in 2013 and 1,634,530 MMbtu of NYMEX swaps in 2014 at a cost of $0.3 million.  In addition, we reduced our outstanding NYMEX swap positions in 2013 by 1,041,814 MMbtu by executing offsetting trades with one of our counterparties at a fixed price of $3.66 per Mcf.  These transactions ensure that our outstanding derivative positions in future periods are lower than our expected future natural gas production in those periods.  We also amended a 2014 to 2015 oil trade with one of our hedge counterparties to lower the stated swap price from $98.10 to $93.50 per barrel, on a total of 58,157 barrels of oil.  We received proceeds of approximately $0.2 million upon execution of the amendment.  The proceeds were used for working capital purposes.
	In March 2013, we reduced our outstanding interest rate swaps that fixed our LIBOR rate through 2014 to $30 million, which resulted in additional interest rate swap settlements of $2.1 million.  This position was terminated in May 2013, resulting in an offsetting non-cash gain in our mark-to-market interest swap activities.
	In May 2013, in conjunction with amendments to our reserve-based credit facility and the exit of certain lenders from our bank syndicate, we novated certain of our commodity hedges to Societe General, which increased our natural gas settlement cost by $0.3 million.

Debt

Debt	12 Months Ended
	Dec. 31, 2014
Debt [Abstract]
Debt	6. DEBT
	Reserve-Based Credit Facility
	In May 2013, we refinanced our $350.0 million reserve-based credit facility with Societe Generale as administrative and collateral agent and a syndicate of lenders, extending its maturity to May 30, 2017 and increasing our borrowing base from $37.5 million to $55.0 million.  On May 6, 2014, our borrowing base under the reserve-based credit facility was increased to $70.0 million. Borrowings under the reserve-based credit facility are secured by various mortgages of oil and natural gas properties that we and certain of our subsidiaries own, as well as various security and pledge agreements among us and certain of our subsidiaries and the administrative agent. The amount available for borrowing at any one time under the reserve-based credit facility is limited to the borrowing base for our oil and natural gas properties.  As of December 31, 2014, we had borrowed $42.5 million under our reserve-based credit facility and our borrowing base was $70.0 million.  At December 31, 2014, the lenders and their percentage commitments in the reserve-based credit facility were Societe Generale (36.36%), OneWest Bank, FSB (36.36%) and BOKF NA, dba Bank of Oklahoma (27.28%).
	Borrowings under the reserve-based credit facility are available for acquisition, exploration, operation and maintenance of oil and natural gas properties, payment of expenses incurred in connection with the reserve-based credit facility, working capital and general limited liability company purposes.  The reserve-based credit facility has a sub-limit of $20.0 million which may be used for the issuance of letters of credit.  As of December 31, 2014, no letters of credit were outstanding.
	At our election, interest for borrowings is determined by reference to (i) the London interbank rate, or LIBOR, plus an applicable margin between 2.50% and 3.50% per annum based on utilization or (ii) a domestic bank rate (ABR) plus an applicable margin between 1.50% and 2.50% per annum based on utilization plus (iii) a commitment fee of 0.50% per annum based on the unutilized borrowing base. Interest on the borrowings for ABR loans and the commitment fee are generally payable quarterly. Interest on the borrowings for LIBOR loans are generally payable at the applicable maturity date.
	The reserve-based credit facility contains various covenants that limit, among other things, our ability and certain of our subsidiaries’ ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of our assets, make certain loans, acquisitions, capital expenditures and investments.  The reserve-based credit facility limits our ability to pay distributions to unitholders and permits us to hedge our projected monthly production, as discussed below, and the interest rate on our borrowings.
	In addition, we are required to maintain (i) a ratio of Total Net Debt (defined as Debt (generally indebtedness permitted to be incurred by us under the reserve-based credit facility) less Available Cash (generally, cash, cash equivalents and cash reserves of the Company)) to Adjusted EBITDA (generally, for any period, the sum of consolidated net income for such period plus (minus) the following expenses or charges to the extent deducted from consolidated net income in such period: interest expense, depreciation, depletion, amortization, write-off of deferred financing fees, impairment of long-lived assets, (gain) loss on sale of assets, exploration costs, (gain) loss from equity investment, accretion of asset retirement obligation, unrealized (gain) loss on derivatives and realized (gain) loss on cancelled derivatives, and other similar charges) of not more than 3.50 to 1.0; (ii) Adjusted EBITDA to cash interest expense of not less than 2.5 to 1.0; and (iii) consolidated current assets, including the unused amount of the total commitments but excluding current non-cash assets, to consolidated current liabilities, excluding non-cash liabilities and current maturities of debt (to the extent such payments are not past due), of not less than 1.0 to 1.0, all calculated pursuant to the requirements under Accounting Standards Codification (ASC) Topic 815, Derivatives and Hedging; ASC Topic 410, Asset Retirement and Environmental Obligations and ASC Topic 360, Property, Plant and Equipment. All financial covenants are calculated using our consolidated financial information and are discussed below.
	The reserve-based credit facility also includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross-defaults, bankruptcy and insolvency events, certain unsatisfied judgments, guaranties not being valid under the reserve-based credit facility and a change of control. A change of control is generally defined as the occurrence of (a) any person or two or more persons acting as a group acquiring beneficial ownership of 35% or more of the outstanding shares of voting stock of the Company or (b) individuals who constitute the current Class B managers of the Company’s current board of managers cease for any reason to constitute at least a majority of the Company’s board of managers; provided however, that any individual becoming a Class B manager whose election, or nomination for election by the Company’s unitholders, was approved by a vote of at least a majority of the Class B managers then comprising the current board, shall be considered as though such person was a Class B manager of the current board of managers, but excluding any such person whose initial assumption of office occurs as a result of either an actual or threatened election contest or other actual or threatened solicitation of proxies or consents by or on behalf of a person other than the Company’s board of managers.  Neither of these events have occurred, so no change in control had occurred as of December 31, 2014.  If an event of default occurs, the lenders will be able to accelerate the maturity of the reserve-based credit facility and exercise other rights and remedies. The reserve-based credit facility contains a condition to borrowing and a representation that no material adverse effect (MAE) has occurred, which includes, among other things, a material adverse change in, or material adverse effect on the business, operations, property, liabilities (actual or contingent) or condition (financial or otherwise) of us and our subsidiaries who are guarantors taken as a whole. If a MAE were to occur, we would be prohibited from borrowing under the reserve-based credit facility and would be in default, which could cause all of our existing indebtedness to become immediately due and payable.
	The reserve-based credit facility limits our ability to pay distributions to unitholders. We have the ability to pay distributions to unitholders from available cash, including cash from borrowings under the reserve-based credit facility, as long as no event of default exists and provided that no distributions to unitholders may be made if the borrowings outstanding, net of available cash, under the reserve-based credit facility exceed 90% of our borrowing base, after giving effect to the proposed distribution. Our available cash is reduced by any cash reserves established by our board of managers for the proper conduct of our business and the payment of fees and expenses. As of December 31, 2014, we were restricted from paying distributions to unitholders as we had no available cash (taking into account the cash reserves set by our board of managers for the proper conduct of our business) from which to pay distributions.
	The reserve-based credit facility permits us to hedge our projected monthly production, provided that (a) for the immediately ensuing twelve-month period, the volumes of production hedged in any month may not exceed our reasonable business judgment of the production for such month consistent with the application of petroleum engineering methodologies for estimating proved developed producing reserves based on the then-current strip pricing (provided that such projection shall not be more than 115% of the proved developed producing reserves forecast for the same period derived from the most recent reserve report of our petroleum engineers using the then strip pricing), and (b) for the period beyond twelve months, the volumes of production hedged in any month may not exceed the reasonably anticipated projected production from proved developed producing reserves estimated by our petroleum engineers. The reserve-based credit facility also permits us to hedge the interest rate on up to 90% of the then-outstanding principal amounts of our indebtedness for borrowed money.
	The reserve-based credit facility contains no covenants related to SOG’s ownership in us, nor to the Services Agreement between us and SP Holding, LLC, a SOG-related company.
	Compliance with Financial Covenants
	At December 31, 2014, we were in compliance with the financial covenant ratios contained in our reserve-based credit facility. We monitor compliance on an ongoing basis. As of December 31, 2014, our actual Total Net Debt to annual Adjusted EBITDA ratio was 1.6 to 1.0, compared to a required ratio of not greater than 3.5 to 1.0; our actual ratio of consolidated current assets to consolidated current liabilities was 5.6 to 1.0, compared to a required ratio of not less than 1.0 to 1.0 and our actual quarterly Adjusted EBITDA to cash interest expense ratio was 13.3 to 1.0, compared to a required ratio of not less than 2.5 to 1.0.
	If we are unable to remain in compliance with the financial covenants contained in our reserve-based credit facility or maintain the required ratios discussed above, the lenders could call an event of default and accelerate the outstanding debt under the terms of our reserve-based credit facility, such that our outstanding debt could become then due and payable. We may request waivers of compliance from the violated financial covenants from the lenders, but there is no assurance that such waivers would be granted.
	The amount available for borrowing at any one time under the reserve-based credit facility is limited to the borrowing base for our oil and natural gas properties.  As of December 31, 2014, our borrowing base was $70.0 million.  The borrowing base is re-determined semi-annually, and may be re-determined at our request more frequently and by the lenders, in their sole discretion, based on reserve reports as prepared by petroleum engineers, using, among other things, the oil and natural gas prices prevailing at such time.  Outstanding borrowings in excess of our borrowing base must be repaid or we must pledge other oil and natural gas properties as additional collateral.  We may elect to pay any borrowing base deficiency in three equal monthly installments such that the deficiency is eliminated in a period of three months.  Any increase in our borrowing base must be approved by all of the lenders.
	Funds Available for Borrowing
	As of December 31, 2014, we had $42.5 million in outstanding debt under our reserve-based credit facility and $27.5 million in remaining borrowing capacity. At December 31, 2013, we had $50.7 million in outstanding debt under our reserve-based credit facility.
	Debt Issue Costs
	As of December 31, 2014, our unamortized debt issue costs were approximately $0.7 million. These costs are being amortized over the life of the credit facility.  At December 31, 2013, our unamortized debt issue costs were approximately $0.8 million.

Oil_And_Natural_Gas_Properties

Oil And Natural Gas Properties	12 Months Ended
	Dec. 31, 2014
Oil And Natural Gas Properties [Abstract]
Oil And Natural Gas Properties	7. OIL AND NATURAL GAS PROPERTIES
	Oil and natural gas properties consist of the following (in thousands):
		December 31,
		2014		2013
	Oil and natural gas properties and related equipment
	(successful efforts method)
	Property (acreage) costs
	Proved property	$	649,432	$	636,816
	Unproved property		1,560		1,589
	Total property costs		650,992		638,405
	Materials and supplies		1,056		1,054
	Land		501		751
	Total		652,549		640,210
	Less: Accumulated depreciation, depletion, amortization and impairments		-517,239		-495,215
	Oil and natural gas properties and equipment, net	$	135,310	$	144,995
	Depreciation, depletion, amortization and impairments consisted of the following (in thousands):
		Year Ended December 31,
		2014		2013
	DD&A of oil and natural gas-related assets	$	17,533	$	18,972
	Asset impairments		5,424		2,357
	Total	$	22,957	$	21,329
	Impairment Charges
	Our non-cash asset impairment charges for the year ended December 31, 2014 were $5.4 million, compared to $2.3 million for the same period in 2013. Our non-cash impairment charges in 2014 were approximately $5.4 million to impair the value of our oil and natural gas fields in Texas and Louisiana due to the decrease in oil prices.
	Our non-cash impairment charges in 2013 were approximately $2.2 million to impair the value of our oil and natural gas fields in Texas and Louisiana and $0.1 million to impair certain of our wells in the Woodford Shale due to decreases in natural gas prices.
	Asset Sales
	In 2014, we sold miscellaneous furniture and fixtures, trucks and equipment resulting in a loss on sale of $0.2 million.
	Useful Lives
	Our furniture, fixtures and equipment are depreciated over a life of one to seven years, buildings are depreciated over a life of 20 years and pipeline and gathering systems are depreciated over a life of 25 to 40 years.
	Exploration and Dry Hole Costs
	We recorded no exploration and dry hole costs for the years ended December 31, 2014 and 2013.  These costs represent abandonments of drilling locations, dry hole costs, delay rentals, geological and geophysical costs and the impairment, amortization and abandonment associated with leases on our unproved properties.

Benefit_Plans

Benefit Plans	12 Months Ended
	Dec. 31, 2014
Benefit Plans [Abstract]
Benefit Plans	8. BENEFIT PLANS
	Eligible employees of SPP participate in an employment savings plan.  Matching contributions made by us were approximately $0.2 million and $0.3 million for the years ended December 31, 2014 and 2013, respectively.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transations	9. RELATED PARTY TRANSACTIONS
	Unit Ownership
	SOG, through a subsidiary, owns a portion of our outstanding units.  As of December 31, 2014, SEP I, a subsidiary of SOG, owned 484,505, or 100%, of our Class A units and 5,364,196, or 18.6%,  of our Class B common units.
	Sanchez-Related Announcements
	In August 2013, SEP I acquired certain of our Class A units and Class B common units and one Class Z unit in one transaction which represented a 20% ownership interest in us at December 31, 2014. These units were issued to SEP I, along with cash, in exchange for oil and natural gas properties located in Texas and Louisiana.  The Company also entered into a Registration Rights Agreement with SEP I pursuant to which the Company granted to SEP I certain registration rights related to the unit consideration.  Under the Registration Rights Agreement, the Company granted SEP I demand registration rights with respect to the preparation and filing with the SEC of one or more registration statements for the purpose of registering the resale of the securities received in the transaction.
	On May 8, 2014, the Company and the Manager, a SOG-related company, entered into the Services Agreement pursuant to which the Manager provides services that the Company requires to operate its business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, professionals and acquisition, disposition and financing services.  In connection with providing the services under the Services Agreement, the Manager receives compensation consisting of: (i) a quarterly fee equal to 0.375% of the value of the Company’s properties other than its assets located in the Mid-Continent region, (ii) a $1,000,000 administrative fee, with $500,000 paid on May 8, 2014 and $500,000 paid on July 1, 2014, the date that the Manager provided notice of its commitment to provide services under the Services Agreement (the In-Service Date), (iii) reimbursement for all allocated overhead costs as well as any direct third-party costs incurred and (iv) for each asset acquisition, asset disposition and financing, a fee not to exceed 2% of the value of such transaction.  Each of these fees, not including the reimbursement of costs, will be paid in cash unless the Manager elects for such fee to be paid in equity by the Company.  In addition, upon the first acquisition of assets from an affiliate of the Manager, the Company is required to amend its operating agreement and issue a new class of incentive distribution rights to the Manager.
	The Services Agreement has a ten-year term and will be automatically renewed for an additional ten years unless both the Manager and the Company provide notice to terminate the agreement.  The Services Agreement can be terminated early (i) by either party at any time after 24 months from the In-Service Date with six months’ notice to the other party, (ii) by either party if there is an uncured material breach thereunder by the other party or (iii) by the Company if there is a change in control of the Manager and the Company pays the termination payment discussed below.  If there is a termination of the Services Agreement other than by either party at the end of the agreement’s term or by the Company for a breach by the Manager, then the Company will owe a termination payment to the Manager equal to $5,000,000, plus 5% of the transaction value of all asset acquisitions theretofore consummated; if the Company terminates after the 24-month anniversary of the In-Service Date upon six months’ notice, the Company will also owe to the Manager all costs and expenses of the Manager that result from such termination.  Through December 31, 2014, the Company has paid $6.0 million to the Manager under the Services Agreement and issued 59,562 common units to SP Holdings pursuant to the Services Agreement in connection with SP Holdings’ election to receive payment of their fee for the quarter ended September 30, 2014 in common units rather than cash.  The issuance of the common units was in lieu of paying a fee of $165,582 in cash, or $2.78 per common unit.
	On May 8, 2014, the Company and SOG entered into a Contract Operating Agreement (the Operating Agreement) pursuant to which SOG has agreed either to provide services to operate, develop and produce the Company’s oil and natural gas properties or to engage a third-party operator to do so, other than with respect to the Company’s properties in the Mid-Continent region.  In connection with providing services under the Operating Agreement, SOG will be reimbursed for all direct charges under COPAS.
	On May 8, 2014, the Company, the Manager and SOG entered into a Transition Agreement (the Transition Agreement) pursuant to which the Company agreed to make available to the Manager and SOG certain of the Company’s employees for SOG or the Manager to provide services under the Services Agreement and Operating Agreement.  No compensation was paid by any party for the provision or use of employees under the Transition Agreement.  All employees remained under the day-to-day control of the Company, and the Company retained the right to terminate employees and had no obligation to hire new employees.  SOG had the right to hire any Company employees and thereafter, SOG is responsible for all costs and expenses for such employees.  As of the In-Service Date, all employees of the Company located in the Houston office became employees of SOG, except for the Chief Executive Officer and the Chief Financial Officer, who remain employees of the Company.
	On May 8, 2014, the Company, SOG and certain subsidiaries of the Company entered into a Geophysical Seismic Data Use License Agreement (the License Agreement) pursuant to which SOG provides to the Company a non-exclusive, royalty-free license to use seismic, geophysical and geological information relating to the Company’s oil and natural gas properties that is proprietary to SOG and not restricted by agreements that SOG has with landowners or seismic data vendors.  No amounts are payable under the agreement.
	Class Z Unit
	SEP I holds the one Class Z unit of SPP.  This one unit is a non-voting unit, except voting as a separate class must approve the issuance of additional Company securities, other than Class B common units, prior to the issuance of such securities.  The Class Z unit is a non-economic interest, without any right to participate in distributions or allocations.

Commitments_And_Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments And Contingencies [Abstract]
Commitments And Contingencies	10. COMMITMENTS AND CONTINGENCIES
	Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any other material legal proceedings other than those that have been previously disclosed.  In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under various environmental protection statutes or other regulations to which we are subject.
	On August 30, 2013, a lawsuit was filed in the Chancery Court of the State of Delaware by Constellation Energy Partners Management, LLC (CEPM), Gary M. Pittman and John R. Collins against the Company, certain of its officers and managers, SOG and SEP I (the PostRock Litigation) in connection with the Company’s closing on August 9, 2013 of the purchase of oil and natural gas properties from SEP I and the issuance of units in connection therewith.  The plaintiffs contended, among other things, that the issuance of the units to SEP I in connection with the acquisition was not permitted under the Company’s operating agreement, that Messrs. Pittman and Collins should not have been removed as the Class A managers of the Company’s board of managers, and that SEP I, SOG and our current Class A managers participated in bad faith conduct of the other defendants and interfered with CEPM’s contractual rights under the Company’s operating agreement. The plaintiffs alleged claims against the Company and certain of its managers and officers relating to breach of contract, breach of the duty of good faith, and breach of the implied covenant of good faith and fair dealing; the plaintiffs also alleged aiding and abetting and tortuous interference claims against SOG, SEP I and our current Class A managers.  The plaintiffs sought, among other things, declaratory relief reappointing Messrs. Pittman and Collins to the Company’s board of managers and removing our current Class A managers therefrom, and an injunction against the Company taking any further action outside the ordinary course of business during the pendency of the litigation, declaratory relief rescinding the units issued by the Company to SEP I, declaratory relief that CEPM had sole voting power with respect to the outstanding Class A units, declaratory relief that the Company’s officers and managers breached fiduciary and contractual duties and were not entitled to indemnification from the Company as a result thereof, and monetary damages.  On March 31, 2014, the parties to the lawsuit reached a settlement agreement and the lawsuit was subsequently dismissed.  As a result of the settlement, the Class A units acquired by SEP I in the August 2013 transaction were returned to SPP and cancelled in exchange for $0.8 million; CEPM transferred 100% of its Class A units and 414,938 of SPP’s Class B units to SEP I in exchange for an aggregate payment of $1.0 million from SEP I, and SPP paid $6.5 million to CEPM.  In addition, pursuant to the terms of the settlement, CEPM agreed to sell its remaining Class B units over the next nine months, with SEP I providing up to a $5.0 million backstop payment to CEPM to the extent proceeds received by CEPM from such sale do not meet or exceed a specified amount.  As a result of the settlement, the settling parties filed a stipulation in the Court of Chancery of the State of Delaware seeking to lift the preliminary injunction issued on December 3, 2013, and the litigation was dismissed with prejudice.  The settlement also included mutual releases between the plaintiffs and defendants.  In connection with the settlement, we received $1.25 million on April 10, 2014, under our directors and officers insurance policy.
	On February 28, 2014, a lawsuit was filed in the Chancery Court of the State of Delaware by Constellation Energy Partners Holdings, LLC (CEPH) against the Company (the Exelon Litigation) seeking repayment of suspended distributions in relation to the Class D Interests held by CEPH.  In 2006, Constellation Holding, Inc (CHI), which merged with and into CEPH in December 2012, purchased the Company’s Class D Interests for $8.0 million.  The $8.0 million was to be repaid to CEPH in quarterly distributions of $333,333.33 over a period of six years; however, these distributions could be temporarily suspended if a dispute arose over pricing formulas related to the sale of natural gas from the Robinson’s Bend properties.  A dispute arose, so the distributions were suspended pursuant to the Company’s operating agreement and never reinstated.  CEPH contended, among other things, that the Company breached its contract to pay the quarterly distributions, acted in bad faith and received unjust enrichment by suspending the quarterly distributions.  On June 26, 2014, the parties to the lawsuit reached a settlement agreement and the lawsuit was subsequently dismissed.  In conjunction with the settlement, we paid CEPH $1.65 million in exchange for all of the Class C management incentive interests and the Class D interests held by CEPH, which accounted for all such interests issued by SPP.  Effective with the acquisition from CEPH, we cancelled the Class C management incentive interests and Class D interests.

Asset_Retirement_Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	11. ASSET RETIREMENT OBLIGATION
	We recognize the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred if a reasonable estimate of fair value can be made. Each period, we accrete the ARO to its then present value. The associated asset retirement cost (ARC) is capitalized as part of the carrying amount of our oil and natural gas properties, equipment and facilities. Subsequently, the ARC is depreciated using a systematic and rational method over the asset’s useful life. The AROs recorded by us relate to the plugging and abandonment of oil and natural gas wells, and decommissioning of oil and natural gas gathering and other facilities.
	Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions result in adjustments to the recorded fair value of the existing ARO, a corresponding adjustment is made to the ARC capitalized as part of the oil and natural gas property balance.
	The following table is a reconciliation of the ARO (in thousands):
		December 31,
		2014		2013
	Asset retirement obligation, beginning balance	$	9,513	$	7,665
	Liabilities added from acquisitions		80		1,088
	Liabilities added from drilling		59		244
	Revisions to cost estimates		6,780		-
	Settlements		-5		-3
	Accretion expense		604		519
	Asset retirement obligation, ending balance	$	17,031	$	9,513
	Additional retirement obligations increase the liability associated with new oil and natural gas wells and other facilities as these obligations are incurred. Actual expenditures for abandonments of oil and natural gas wells and other facilities reduce the liability for asset retirement obligation. In 2014 and 2013, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing asset retirement obligations.  During the year ended December 31, 2014, revisions were made to the ARO liability based on recent costs incurred on abandoned wells, which were higher than originally projected.

UnitBased_Compensation

Unit-Based Compensation	12 Months Ended
	Dec. 31, 2014
Unit-Based Compensation [Abstract]
Unit-Based Compensation	12. UNIT-BASED COMPENSATION
	We have the following unit-based compensation plans:
	We have the 2009 Omnibus Incentive Compensation Plan (Omnibus Plan), which provides for a variety of unit-based and performance-based awards, including unit options, restricted units, unit grants, notional units, unit appreciation rights, performance awards and other unit-based awards.  Awards under the Omnibus Plan may be paid in cash, units or any combinations thereof as determined by the compensation committee of our board of managers.
	Restricted unit activity (number of units) under the Omnibus Plan was as follows:
			Weighted
			Average
		Number of	Grant Date
		Restricted	Fair Value
		Units	Per Unit
	Outstanding at December 31, 2012	666,778	$	3.39
	Vested	-370,363		2.66
	Granted	184,313		1.27
	Returned/Cancelled	-144,177		2.77
	Outstanding at December 31, 2013	336,551		3.29
	Vested	-450,958		2.80
	Granted	346,403		2.44
	Returned/Cancelled	-151,842		2.86
	Outstanding at December 31, 2014	80,154	$	3.18
	We have the Long-Term Incentive Program (L-TIP), which is a plan under which restricted common unit awards have been granted to certain field employees in Alabama, Kansas and Oklahoma and to certain employees in Texas.
	Restricted unit activity (number of units) under the L-TIP Plan was as follows:
			Weighted
			Average
		Number of	Grant Date
		Restricted	Fair Value
		Units	Per Unit
	Outstanding at December 31, 2012	94,914	$	3.05
	Vested	-61,273		2.24
	Granted	38,023		1.17
	Returned/Cancelled	-27,888		2.56
	Outstanding at December 31, 2013	43,776		2.87
	Vested	-99,381		2.51
	Granted	103,278		2.44
	Returned/Cancelled	-27,002		2.57
	Outstanding at December 31, 2014	20,671	$	2.83
	We recognized approximately $1.3 million and  $1.0 million of non-cash compensation expense related to our unit-based compensation plans in the twelve months ended December 31, 2014 and 2013, respectively. As of December 31, 2014, we had approximately $0.1 million in unrecognized compensation expense related to our unit-based compensation plans expected to be recognized through the first quarter of 2015.
	On December 18, 2014, the compensation committee of our board of managers awarded notional units under the Omnibus Plan to each of our executive officers.  The notional amounts awarded were 769,231 units to our Chief Executive Officer and 256,410 units to our Chief Financial Officer.  The notional units will convert on a one-for-one basis into restricted common units of Sanchez Production Partners LP upon unitholder approval of a proposed Sanchez Production Partners LP Long-Term Incentive Plan and the conversion of the Company from a limited liability company into a limited partnership becoming effective.  The notional units or restricted units, as applicable, will vest in one-third increments on each December 15, 2015, 2016 and 2017.  If the new plan is not approved, or the foregoing two conditions are not otherwise satisfied by the applicable vesting date, then the notional units then vesting will be settled in cash at the fair market value of the Company’s common units as of such date.  Each notional unit carries the right to receive distribution credits when any distributions are made by the Company on its common units, which will be settled in cash when the notional units are converted or settled, as applicable.  This award was classified as a liability-classified award as of and for the year ended December 31, 2014.  As a liability-classified award, the fair value of the award is re-measured at each financial statement date until the award is settled or expires.  During the requisite service period, compensation cost is recognized using the proportionate amount of the award’s fair value that has been earned through service to date.

Distributions_To_Unitholders

Distributions To Unitholders	12 Months Ended
	Dec. 31, 2014
Distributions To Unitholders [Abstract]
Distributions To Unitholders	13. DISTRIBUTIONS TO UNITHOLDERS
	Beginning in June 2009, we suspended our quarterly distributions to unitholders. For twelve months ended December 31, 2014 and 2013, respectively, we were restricted from paying distributions to unitholders as we had no available cash (taking into account the cash reserves set by our board of managers for the proper conduct of our business) from which to pay distributions.

Members_Equity

Members' Equity	12 Months Ended
	Dec. 31, 2014
Members' Equity [Abstract]
Members' Equity	14. MEMBERS’ EQUITY
	2014 Equity
	At December 31, 2014, we had 484,505 Class A units and 28,792,584 Class B common units outstanding, which included 20,671 unvested restricted common units issued under our L-TIP and 80,154 unvested restricted common units issued under our Omnibus Plan.
	At December 31, 2014, we had granted 423,010 common units of the 450,000 common units available under our L-TIP. Of these grants, 402,339 have vested.
	At December 31, 2014, we had granted 1,561,227 common units of the 1,650,000 common units available under our Omnibus Plan. Of these grants, 1,481,073 have vested.
	For the year ended December 31, 2014, 160,182 common units were tendered by our employees for minimum tax withholding purposes. These units, costing approximately $0.4 million, have been returned to their respective plan and are available for future grants.
	2013 Equity
	At December 31, 2013, we had 1,615,017 Class A units and 28,462,185 Class B common units outstanding, which included 43,776 unvested restricted common units issued under our L-TIP and 336,551 unvested restricted common units issued under our Omnibus Plan.
	At December 31, 2013, we had granted 346,734 common units of the 450,000 common units available under our L-TIP. Of these grants, 302,958 have vested.
	At December 31, 2013, we had granted 1,366,666 common units of the 1,650,000 common units available under our Omnibus Plan. Of these grants, 1,030,115 have vested.
	For the year ended December 31, 2013, 139,810 common units were tendered by our employees for minimum tax withholding purposes. These units, costing approximately $0.2 million, have been returned to their respective plan and are available for future grants.

Supplemental_Information_On_Oi

Supplemental Information On Oil And Natural Gas Producing Activities	12 Months Ended
	Dec. 31, 2014
Supplemental Information On Oil And Natural Gas Producing Activites [Abstract]
Supplemental Information On Oil And Natural Gas Producing Activities	15.SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
	The Supplementary Information on Oil and Natural Gas Producing Activities is presented as required by the appropriate authoritative guidance. The supplemental information includes capitalized costs related to oil and natural gas producing activities; costs incurred for the acquisition of oil and natural gas producing activities, exploration and development activities and the results of operations from oil and natural gas producing activities.
	Supplemental information is also provided for per unit production costs; oil and natural gas production and average sales prices; the estimated quantities of proved oil and natural gas reserves; the standardized measure of discounted future net cash flows associated with proved reserves and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved reserves.
	Costs
	The following table sets forth capitalized costs for the years ended December 31, 2014 and 2013 (in thousands):
		December 31,
		2014			2013
	Capitalized costs at the end of the period:⁽ᵃ⁾
	Oil and natrual gas properties and related equipment (successful efforts method)
	Property costs
	Proved property	$	649,432		$	636,816
	Unproved property		1,560			1,589
	Total property costs		650,992			638,405
	Materials and supplies		1,056			1,054
	Land		501			751
	Total		652,549			640,210
	Less: Accumulated depreciation, depletion, amortization and impairments		-517,239			-495,215
	Oil and natural gas properties and equipment, net	$	135,310		$	144,995
	(a)Capitalized costs include the cost of equipment and facilities for our oil and natural gas producing activities. Proved property costs include capitalized costs for leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); and support equipment. Unproved property costs include capitalized costs for oil and natural gas leaseholds where proved reserves do not exist.
	The following table sets forth costs incurred for oil and natural gas producing activities for the years ended December 31, 2014 and 2013 (in thousands):
		For the year ended December 31,
		2014			2013
	Costs incurred for the period:
	Acquisition of properties
	Proved	$	1,239		$	20,012
	Unproved		112			209
	Development costs		5,865			15,694
	Oil and natural gas properties and equipment, net	$	7,216		$	35,915
	The development costs for the years ended December 31, 2014 and 2013 primarily represent costs to develop our proved undeveloped reserves.  The properties acquired in 2014 and 2013 were in Texas and Louisiana.
	We had no exploration and dry hole costs in 2014 and 2013, respectively.
	Results of Operations
	The revenues and expenses associated directly with oil and natural gas producing activities are reflected in the Consolidated Statements of Operations.  All of our operations are oil and natural gas producing activities located in the United States.
	Net Proved Oil, Natural Gas and Natural Gas Liquids Reserves
	The following table sets forth information with respect to changes in proved developed and undeveloped reserves. This information excludes reserves related to royalty and net profit interests. All of our reserves are located in the United States.
								Natural Gas
		Total		Oil		Natural Gas		Liquids
		(Mmcfe)		(in Mmcfe)		(in Mmcfe)		(in Mmcfe)
	Net proved reserves
	31-Dec-12	92,982		6,503		-		86,479
	Extensions and discoveries	4,825		4,016		128		681
	Puchase of reserves in place	7,150		1,668		523		4,959
	Sales of reserves in place	-49,385		-		-		-49,385
	Revisions of previous estimates	44,727		1,147		207		43,373
	Production	-9,045		-901		-		-8,144
	31-Dec-13	91,254		12,433		858		77,963
	Extensions and discoveries	3,052		2,493		-		559
	Puchase of reserves in place	437		437		-		-
	Revisions of previous estimates	14,163		-3,542		-340		18,045
	Production	-9,143		-1,849		-169		-7,125
	31-Dec-14	99,763		9,972		349		89,442
	Proved developed reserves:
	31-Dec-13	78,629		11,170		858		66,601
	31-Dec-14	74,634		9,139		349		65,146
	Proved undeveloped reserves:
	31-Dec-13	12,625		1,264		-		11,361
	31-Dec-14	25,129		833		-		24,296
	Reserves and Related Estimates
	Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters.
	Our December 31, 2014 and 2013 proved reserve estimates were 99.8 Bcfe and 91.3 Bcfe, respectively. For these years, NSAI, an independent petroleum engineering firm, prepared the estimates of our proved reserves which were used to prepare our financial statements.
	Our 2014 estimates of total proved reserves increased 8.5 Bcfe from 2013 due to a 12.9 Bcfe increase in undeveloped gas reserves in the Cherokee Basin.  The higher volumes were due to a higher gas price.  Our reserves are 90% natural gas and are sensitive to lower prices for natural gas and basis differentials in the Mid-Continent region.  For the proved reserves, the production weighted average product price over the remaining lives of the properties used in our reserve report: $93.95 per barrel for oil, $35.11 per barrel for natural gas liquids and $4.09 per Mcf for natural gas.  Proved developed producing reserves were lower due to natural production decline.
	Our 2013 estimates of total proved reserves decreased 1.7 Bcfe from 2012 due to the sale of our Black Warrior Basin properties in the amount of 49 Bcfe offset by the acquisition of the Sanchez properties, which added 7 Bcfe. We added 4.8 Bcfe due to extensions and discoveries in the Cherokee Basin reserves added for oil opportunities. Our reserve revisions of 44.8 Bcfe were primarily the result of higher natural gas prices. Our reserves were 85% natural gas and were sensitive to lower prices for natural gas and basis differentials in the Mid-Continent region. For the proved reserves, the production weighted average product price over the remaining lives of the properties used in our reserve report were: $97.89 per barrel for oil, $41.21 per barrel for natural gas liquids and $3.706 per Mcf for natural gas. Any of our locations that are scheduled to be drilled after 5 years were classified as probable or possible reserves to the extent they were economic.
	Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas Reserves, Including a Reconciliation of Changes Therein
	The following table sets forth the standardized measure of the discounted future net cash flows attributable to our proved oil and natural gas reserves. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below.
	Future cash inflows are calculated by applying the SEC-required prices of oil and natural gas relating to our proved reserves to the year-end quantities of those reserves. Future cash inflows exclude the impact of our hedging program. Future development and production costs represent the estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. In addition, asset retirement obligations are included within future production and development costs. There are no future income tax expenses because SPP is a non-taxable entity.
The assumptions used to compute estimated future cash inflows do not necessarily reflect expectations of actual revenues or costs or their present values. In addition, variations from expected production rates could result directly or indirectly from factors outside of our control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production; however, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.
The following table summarizes the standardized measure of estimated discounted future cash flows from the oil and natural gas properties (in thousands):
		For the year ended December 31,
		2014			2013
Future cash inflows		$	532,152		$	502,831
Future production costs			-260,909			-227,315
Future estimated development costs			-57,741			-40,694
Future net cash flows			213,502			234,822
10% annual discount for estimated timing of cash flows			-93,969			-91,108
Standardized measure of discounted estimated future net cash
	flows related to proved gas reserves	$	119,533		$	143,714
The following table summarizes the principal sources of change in the standardized measure of estimated discounted future net cash flows (in thousands):
		For the year ended December 31,
		2014			2013
Beginning of the period		$	143,714		$	89,669
Sales and transfers of oil and natural gas, net of production costs			-38,817			-21,244
Net changes in prices and production costs related to future production			-18,410			50,425
Development costs incurred during the period			18,075			5,615
Changes in extensions and discoveries			24,611			28,494
Revisions of previous quantity estimates			-22,034			21,455
Purchases and sales of reserves in place			1,918			-2,297
Accretion discount			14,371			8,967
Other			-3,895			-37,370
Standardized measure of discounted future net cash flows related to
	proved gas reserves	$	119,533		$	143,714

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Organization And Basis Of Presentation [Abstract]
Organization	Basis of Presentation
	Accounting policies used by us conform to accounting principles generally accepted in the United States of America. The accompanying financial statements include the accounts of us and our wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. We operate our oil and natural gas properties as one business segment: the exploration, development and production of oil and natural gas. Our management evaluates performance based on one business segment as there are not different economic environments within the operation of our oil and natural gas properties.
Use Of Estimates	Use of Estimates
	Estimates and assumptions are made when preparing financial statements under accounting principles generally accepted in the United States of America. These estimates and assumptions affect various matters, including:
	•reported amounts of revenue and expenses in the Consolidated Statements of Operations during the reported periods,
	•reported amounts of assets and liabilities in the Consolidated Balance Sheets at the dates of the financial statements,
	•disclosure of quantities of reserves and use of those reserve quantities for depreciation, depletion and amortization, and
	•disclosure of contingent assets and liabilities at the date of the financial statements.
	These estimates involve judgments with respect to numerous factors that are difficult to predict and are beyond management’s control.  As a result, changes in facts and circumstances or additional information may result in revised estimates or actual amounts may materially differ from these amounts.
Reclassifications	Reclassifications
	Certain reclassifications have been made to the prior periods to conform to the current period presentation.  These reclassifications had no effect on total assets, total liabilities, total unitholders’ equity, net income or net cash provided by or used in operating, investing or financing activities.
Discontinued Operations	Discontinued Operations
	In February 2013, we sold all of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama.  The related results of operations and cash flows have been classified as discontinued operations in the consolidated statements of operations, balance sheets, statements of cash flows and consolidated financial information.  Unless otherwise indicated, information presented in the Notes to Consolidated Financial Statements relates only to the Company’s continuing operations.  Information related to discontinued operations is included in Note 2. Discontinued Operations.
Cash And Cash Equivalents	Cash and Cash Equivalents
	All highly liquid investments with original maturities of three months or less are considered cash equivalents. Checks-in-transit are included in accounts payable in our consolidated balance sheets.
Restricted Cash	Restricted Cash
	Restricted cash at December 31, 2014 and 2013 of $1.7 million was held in escrow in relation to the sale of the Robinson’s Bend Field assets and related to litigation involving one of our service providers.
Concentration Of Credit Risk And Accounts Receivable	Concentration of Credit Risk and Accounts Receivable
	Financial instruments that potentially subject us to a concentration of credit risk consist of cash and cash equivalents, accounts receivable and derivative financial instruments. We place our cash with high credit quality financial institutions. We place our derivative financial instruments with financial institutions that participate in our reserve-based credit facility and maintain an investment grade credit rating. Substantially all of our accounts receivables are due from purchasers of oil and natural gas. These sales are generally unsecured and, in some cases, may carry a parent guarantee. As we generally have fewer than 10 large customers for our oil and natural gas sales, we routinely assess the financial strength of our customers. Bad debt expense is recognized on an account-by-account review and when recovery is not probable. Our allowance for doubtful accounts was $0.2 million during 2014 and less than $0.1 million in 2013. We have no off-balance-sheet credit exposure related to our operations or customers.
	For the year ended December 31, 2014, five customers accounted for approximately 33%,  30%,  16%,  14% and 7% of our sales revenues. For the year ended December 31, 2013, five customers accounted for approximately 22%,  20%,  17%,  14% and 8% of our sales revenues.
Oil And Natural Gas Properties	Oil and Natural Gas Properties
	Oil and Natural Gas Properties
	We follow the successful efforts method of accounting for our oil and natural gas exploration, development and production activities. Leasehold acquisition costs, property acquisition and the costs of development of proved areas are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred.
	Accounting rules require that we price our oil and natural gas proved reserves at the preceding twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. Such SEC-required prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Our proved reserve estimates exclude the effect of any derivatives we have in place.
	Depreciation, Depletion and Amortization
	Depreciation and depletion of producing oil and natural gas properties is recorded at the field level, based on the units-of-production method. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (including wells and related equipment and facilities) are amortized on the basis of proved developed reserves. It has been our historical practice to use our year-end reserve report to adjust our depreciation, depletion, and amortization expense for the fourth quarter. Depreciation, depletion, and amortization expense is calculated using year-end reserve reports based on the SEC-required price. As more fully described in Note 15, proved reserves estimates are subject to future revisions when additional information becomes available.
	Asset Retirement Obligation
	As described in Note 11, estimated asset retirement costs are recognized when the asset is acquired or placed in service, and are amortized over proved developed reserves using the units-of-production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.
	Unsuccessful Wells
	Geological, geophysical and dry hole costs on oil and natural gas properties relating to unsuccessful exploratory wells are charged to expense as incurred.
	Impairment
	Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. The cash flow estimates are based upon third party reserve reports using future expected oil and natural gas prices adjusted for basis differentials. Cash flow estimates for the impairment testing exclude derivative instruments. Refer to Note 7 for additional information.
	Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that we expect to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period. The valuation allowances are reviewed at least annually.
	Property acquisition costs are capitalized when incurred.
	Support Equipment and Facilities
	Support equipment and facilities consist of certain of our water treatment facilities, gathering lines, roads, pipelines and other various support equipment. Items are capitalized when acquired and depreciated using the straight-line method over the useful life of the assets.
	Materials and Supplies
	Materials and supplies consist of well equipment, parts and supplies. They are valued at the lower of cost or market, using either the specific identification or first-in first-out method, depending on the inventory type. Materials and supplies are capitalized as used in the development or support of our oil and natural gas properties.
Oil, Natural Gas And Natural Gas Liquids Reserve Quantities	Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
	Our estimate of proved reserves is based on the quantities of oil, natural gas and natural gas liquids that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Proved reserves are calculated based on various factors, including consideration of an independent reserve engineers’ report on proved reserves and an economic evaluation of all of our properties on a well-by-well basis. The process used to complete the estimates of proved reserves at December 31, 2014 and 2013 is described in detail in Note 15.
	Reserves and their relation to estimated future net cash flows impact depletion and impairment calculations. As a result, adjustments to depletion and impairments are made concurrently with changes to reserve estimates. The accuracy of reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.
	Proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.
Derivatives And Hedging Activities	Derivatives and Hedging Activities
	We use derivative financial instruments to achieve a more predictable cash flow from our oil and natural gas production by reducing our exposure to price fluctuations. Additionally, we use derivative financial instruments in the form of interest rate swaps to mitigate interest rate exposure on our borrowings under our reserve-based credit facility.
	We account for all our open derivatives as mark-to-market activities. All derivative instruments are recorded in the consolidated balance sheet as either an asset or a liability measured at fair value with changes in fair value recognized in earnings. All of our open derivatives are effective as economic hedges of our commodity price or interest rate exposure. These contracts are accounted for using the mark-to-market accounting method. Using this method, the contracts are carried at their fair value on our consolidated balance sheets under the captions “Risk management assets” and “Risk management liabilities.” We recognize all unrealized and realized gains and losses related to these contracts on our consolidated statements of operations under the caption “Oil sales” or “Natural gas sales” and settled interest rate swaps as “Interest expense.”
Revenue Recognition	Revenue Recognition
	Sales are recognized when oil, natural gas and natural gas liquids have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Oil, natural gas and natural gas liquids are generally sold on a monthly basis. Most of the contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a specific tank battery, gathering or transmission line, quality of oil, natural gas and natural gas liquids, and prevailing supply and demand conditions, so that the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies. As a result, revenues from the sale of oil, natural gas and natural gas liquids will suffer if market prices decline and benefit if they increase. We believe that the pricing provisions of our oil, natural gas and natural gas liquids contracts are customary in the industry.
	Gas imbalances occur when sales are more or less than the entitled ownership percentage of total gas production. We use the entitlements method when accounting for gas imbalances. Any amount received in excess is treated as a liability. If less than the entitled share of the production is received, the excess is recorded as a receivable.  There was only a minimal gas imbalance position on one of our wells in the Mid-continent region at December 31, 2014. There were no gas imbalance positions at December 31, 2013.
Income Taxes	Income Taxes
	SPP and each of its wholly-owned subsidiary LLCs are treated as a partnership for federal and state income tax purposes.  All of our taxable income or loss, which may differ considerably from net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our members. As such, no federal income tax for these entities has been provided for in the accompanying financial statements. SPP is subject to franchise tax obligations in Kansas and Texas and state tax obligations in Alabama and Oklahoma. SPP also has informational filing requirements in Georgia, Indiana, Louisiana, Maine, Missouri, New Jersey, New York, Oregon, Pennsylvania, and West Virginia because we have resident unitholders in these states.
	Our wholly-owned subsidiary, CEP Services Company, Inc. is a taxable entity. For the years ended December 31, 2014, and 2013, the current and deferred income taxes for the entity were immaterial. The entity has no material deferred tax assets or liabilities.
Earnings Per Unit	Earnings per Unit
	Basic earnings per unit (EPU) is computed from the two-class method by dividing net income (loss) attributable to unitholders by the weighted average number of units outstanding during each period.  To determine net income (loss) allocated to each class of ownership (Class A and Class B), we first allocate net income (loss) in accordance with the amount of distributions made for the period by each class, if any.  The remaining net income (loss) is allocated to each class in proportion to the class weighted average number of units outstanding for the period, as compared to the weighted average number of units for all classes for the period.
	As of December 31, 2014 and 2013, we had unvested restricted common units outstanding, which were considered dilutive securities.  These units will be considered in the diluted weighted average common units outstanding number in periods of net income.  In periods of net losses, these units are excluded for the diluted weighted average common unit outstanding number as they are not participating securities.
	The following table presents our calculation of basic and diluted units outstanding for the periods indicated:
		Year Ended December 31,
		2014		2013
	Weighted average units outstanding during period:
	Class A units - Basic		763,261		933,613
	Class B Common units - Basic		28,431,586		25,210,106
			29,194,847		26,143,719
	Weighted average units outstanding during period:
	Class A units - Diluted		763,261		933,613
	Class B Common units - Diluted		28,532,411		25,210,106
			29,295,672		26,143,719
	At December 31, 2014, we had 100,825 Class B common units that were restricted unvested common units granted and outstanding.  These units were included in the diluted weighted average common units outstanding number since we recognized net income for the period.  At December 31, 2013, we had 380,327 Class B common units that were restricted unvested common units granted and outstanding.  These units were excluded from the diluted weighted average common units outstanding number since we recognized a net loss for the year.
	The following table presents our basic and diluted income per unit for the year ended December 31, 2014 (in thousands, except for per unit amounts):
		Total		Class A Units		Class B Units
	Income from continuing operations	$	9,503
	Distributions		-	$	-	$	-
	Assumed allocation of income from continuing operations		9,503		190		9,313
	Discontinued operations		-		-		-
	Assumed net income to be allocated	$	9,503	$	190	$	9,313
	Basic and diluted income from continuing operations per unit			$	0.25	$	0.33
	Basic and diluted income from discontinued operations per unit			$	-	$	-
	Basic and diluted income per unit			$	0.25	$	0.33
	The following table presents our basic and diluted income per unit for the year ended December 31, 2013 (in thousands, except for per unit amounts):
		Total		Class A Units		Class B Units
	Loss from continuing operations	$	-25,857
	Distributions		-	$	-	$	-
	Assumed allocation of loss from continuing operations		-25,857		-517		-25,340
	Discontinued operations		-2,686		-53		-2,633
	Assumed net loss to be allocated	$	-28,543	$	-570	$	-27,973
	Basic and diluted loss from continuing operations per unit			$	-0.55	$	-1.01
	Basic and diluted loss from discontinued operations per unit			$	-0.06	$	-0.1
	Basic and diluted loss per unit			$	-0.61	$	-1.11
Environmental Cost	Environmental Cost
	We record environmental liabilities at their undiscounted amounts on our balance sheets in other current and long-term liabilities when our environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Federal Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods.  At December 31, 2014, we had no environmental liabilities recorded, as no liabilities were deemed necessary.
Unit-Based Compensation	Unit-Based Compensation
	We record compensation expense for all equity grants issued under the Long-Term Incentive Program and the 2009 Omnibus Incentive Compensation Plan based on the fair value at the grant date, recognized over the vesting period.
Other Contingencies	Other Contingencies
	We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates it is both probable that an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. Funds spent to remedy these contingencies are charged against the associated reserve, if one exists, or expensed. When a range of probable loss can be estimated, we accrue the most likely amount or at least the minimum of the range of probable loss.
Recent Pronouncements And Accounting Changes	Recent Pronouncements and Accounting Changes
	From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (the FASB), which are adopted by us as of the specified effective date.  Unless otherwise discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on our consolidated financial statements upon adoption.
	In April 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.  This guidance changes the definition of a discontinued operation to include only those disposals of components of an entity that represent a strategic shift that has or will have a major effect on an entity’s operations and financial results.  This guidance is effective prospectively for fiscal years beginning after December 15, 2014.  The effects of this accounting standard on our financial position, results of operations and cash flows will not be material.
	In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606).  This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance.  This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized.  The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services.  The new guidance may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the date of initial application.  We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material.
	In August 2014, the FASB issued ASU No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.  This guidance creates a new subtopic ASC 205-40, “Presentation of Financial Statements – Going Concern,” and provides guidance about management’s responsibility to evaluate whether there is a substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures.  The requirements in this guidance are effective for the annual period ending after December 15, 2016, which is fiscal 2017 for us, and for annual and interim periods thereafter.  Early application is permitted.  We acknowledge this new guidance and will comply with the disclosure requirements, if applicable, beginning in fiscal 2017.  The adoption of this guidance will have no material impact on our financial position, results of operations or cash flows.

Summary_Of_Significant_Account2

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Summary Of Significant Accounting Policies [Abstract]
Schedule Of Weighted Average Units Outstanding
		Year Ended December 31,
		2014		2013
	Weighted average units outstanding during period:
	Class A units - Basic		763,261		933,613
	Class B Common units - Basic		28,431,586		25,210,106
			29,194,847		26,143,719
	Weighted average units outstanding during period:
	Class A units - Diluted		763,261		933,613
	Class B Common units - Diluted		28,532,411		25,210,106
			29,295,672		26,143,719
Earnings Per Common Unit Amounts	The following table presents our basic and diluted income per unit for the year ended December 31, 2014 (in thousands, except for per unit amounts):
		Total		Class A Units		Class B Units
	Income from continuing operations	$	9,503
	Distributions		-	$	-	$	-
	Assumed allocation of income from continuing operations		9,503		190		9,313
	Discontinued operations		-		-		-
	Assumed net income to be allocated	$	9,503	$	190	$	9,313
	Basic and diluted income from continuing operations per unit			$	0.25	$	0.33
	Basic and diluted income from discontinued operations per unit			$	-	$	-
	Basic and diluted income per unit			$	0.25	$	0.33
	The following table presents our basic and diluted income per unit for the year ended December 31, 2013 (in thousands, except for per unit amounts):
		Total		Class A Units		Class B Units
	Loss from continuing operations	$	-25,857
	Distributions		-	$	-	$	-
	Assumed allocation of loss from continuing operations		-25,857		-517		-25,340
	Discontinued operations		-2,686		-53		-2,633
	Assumed net loss to be allocated	$	-28,543	$	-570	$	-27,973
	Basic and diluted loss from continuing operations per unit			$	-0.55	$	-1.01
	Basic and diluted loss from discontinued operations per unit			$	-0.06	$	-0.1
	Basic and diluted loss per unit			$	-0.61	$	-1.11

Discontinued_Operations_Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2014
Discontinued Operations [Abstract]
Schedule Of Discontinued Operations
		Year Ended
		31-Dec-13
	Revenues	$	2,304
	Loss from discontinued operations	$	-2,686

Acquisitions_Tables

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2014
Acquisitions [Abstract]
Estimated Values Of Assets Acquired And Liabilities Assumed
	Oil and natural gas properties, equipment and facilities	$	31,497
	Asset retirement obligation		-1,088
	Net assets acquired	$	30,409
Revenues And Lease Operating Expenses
		Twelve Months Ended
		December 31,
		2013
	Revenue	$	15,782
	Lease Operating Expenses	$	3,047
Supplemental Pro Forma Information
		Pro Forma
		Twelve Months Ended
		December 31,
	(In thousands)	2013
	Revenue	$	56,841
	Income (loss) from continuing operations	$	-18,514
	Discontinued operations	$	-2,686
	Net Loss	$	-21,200
	Income (loss) from continuing operations per unit
	Class A units - Basic and diluted	$	-0.23
	Class B units - Basic and diluted	$	-0.65
	Discontinued operations per unit
	Class A units - Basic and diluted	$	-0.03
	Class B units - Basic and diluted	$	-0.09
	Net loss per unit
	Class A units - Basic and diluted	$	-0.26
	Class B units - Basic and diluted	$	-0.74
	Weighted average units outstanding
	Class A units - Basic and diluted		1,615,103
	Class B units - Basic and diluted		28,057,592

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Measurements [Abstract]
Fair Value Of Assets And Liabilities On A Recurring Basis	The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 (in thousands):
		Fair Value Measurements at December 31, 2014
		Quoted Prices in		Significant other
		Active Markets for		Observable		Significant
		Identical Assets		Inputs		Unobservable Inputs		Netting Cash and		Fair Value at
		(Level 1)		(Level 2)		(Level 3)		Collateral		31-Dec-14
	Risk Mgmt Assets	$	—	$	22,919	$	—	$	-90	$	22,829
	Risk Mgmt Liabilities		—		-90		—		90		—
	Total Net Assets and Liabilities	$	—	$	22,829	$	—	$	—	$	22,829
	The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013 (in thousands):
		Fair Value Measurements at December 31, 2013
		Quoted Prices in		Significant other
		Active Markets for		Observable		Significant
		Identical Assets		Inputs		Unobservable Inputs		Netting Cash and		Fair Value at
		(Level 1)		(Level 2)		(Level 3)		Collateral		31-Dec-13
	Risk Mgmt Assets	$	—	$	11,577	$	—	$	-975	$	10,602
	Risk Mgmt Liabilities		—		-975		—		975		—
	Total Net Assets and Liabilities	$	—	$	10,602	$	—	$	—	$	10,602

Derivative_And_Financial_Instr1

Derivative And Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative And Financial Instruments [Abstract]
Summary Of Hedges In Place	MTM Fixed Price Swaps – NYMEX (Henry Hub)
		For the quarter ended (in MMBtu)
		March 31,					June 30,				September 30,			December 31,			Total
				Average					Average			Average			Average			Average
		Volume		Price			Volume		Price		Volume	Price		Volume	Price		Volume	Price
	2015	1,215,420		$	4.25		1,153,487		$	4.25	1,096,023	$	4.26	1,050,219	$	4.26	4,515,149	$	4.26
	2016	1,010,633		$	4.21		967,290		$	4.21	923,541	$	4.21	893,568	$	4.22	3,795,032	$	4.21
																	8,310,181
	MTM Fixed Price Basis Swaps – West Texas Intermediate (WTI)
		For the quarter ended (in Bbls)
		March 31,					June 30,				September 30,			December 31,			Total
				Average					Average			Average			Average			Average
		Volume		Price			Volume		Price		Volume	Price		Volume	Price		Volume	Price
	2015	69,479		$	90.99		66,183		$	91.02	63,025	$	91.05	60,143	$	91.09	258,830	$	91.04
	2016	57,420		$	85.64		54,879		$	85.64	52,474	$	85.64	50,197	$	85.64	214,970	$	85.64
																	473,800
Fair Value for Risk Management Assets and Liabilities
					Fair Value of Asset/(Liability)
			Location of Asset/(Liability)		On Balance Sheet
	Derivative Type		On Balance Sheet		31-Dec-14			31-Dec-13
	Commodity – MTM		Risk management assets - current		$	14,698		$	10,043
	Commodity – MTM		Risk management assets  - non-current			8,221			1,534
			Total gross assets			22,919			11,577
	Commodity – MTM		Risk management assets – current			-27			-903
	Commodity – MTM		Risk management assets – non-current			-63			-72
			Total gross liabilities			-90			-975
			Total net assets and liabilities		$	22,829		$	10,602
Schedule Of Effect Of Derivative Instruments On Condensed Consolidated Statements Of Operations
					Amount of Gain/(Loss) in Income
			Location of Gain/(Loss)		For the Year Ended December 31,
	Derivative Type		in Income		2014			2013
	Commodity – MTM		Oil and natural gas sales		$	19,854		$	-1,486
	Interest Rate – MTM		Interest expense			-			-65
			Total		$	19,854		$	-1,551

Oil_And_Natural_Gas_Properties1

Oil And Natural Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2014
Oil And Natural Gas Properties [Abstract]
Oil and Natural Gas Properties
		December 31,
		2014		2013
	Oil and natural gas properties and related equipment
	(successful efforts method)
	Property (acreage) costs
	Proved property	$	649,432	$	636,816
	Unproved property		1,560		1,589
	Total property costs		650,992		638,405
	Materials and supplies		1,056		1,054
	Land		501		751
	Total		652,549		640,210
	Less: Accumulated depreciation, depletion, amortization and impairments		-517,239		-495,215
	Oil and natural gas properties and equipment, net	$	135,310	$	144,995
Depletion, Depreciation, Amortization and Impairments
		Year Ended December 31,
		2014		2013
	DD&A of oil and natural gas-related assets	$	17,533	$	18,972
	Asset impairments		5,424		2,357
	Total	$	22,957	$	21,329

Asset_Retirement_Obligation_Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation [Abstract]
Reconciliation of Asset Retirement Obligation
		December 31,
		2014		2013
	Asset retirement obligation, beginning balance	$	9,513	$	7,665
	Liabilities added from acquisitions		80		1,088
	Liabilities added from drilling		59		244
	Revisions to cost estimates		6,780		-
	Settlements		-5		-3
	Accretion expense		604		519
	Asset retirement obligation, ending balance	$	17,031	$	9,513

UnitBased_Compensation_Tables

Unit-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2014
2009 Omnibus Incentive Compensation Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Schedule Of Units Granted
			Weighted
			Average
		Number of	Grant Date
		Restricted	Fair Value
		Units	Per Unit
	Outstanding at December 31, 2012	666,778	$	3.39
	Vested	-370,363		2.66
	Granted	184,313		1.27
	Returned/Cancelled	-144,177		2.77
	Outstanding at December 31, 2013	336,551		3.29
	Vested	-450,958		2.80
	Granted	346,403		2.44
	Returned/Cancelled	-151,842		2.86
	Outstanding at December 31, 2014	80,154	$	3.18
Long Term Incentive Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Schedule Of Units Granted
			Weighted
			Average
		Number of	Grant Date
		Restricted	Fair Value
		Units	Per Unit
	Outstanding at December 31, 2012	94,914	$	3.05
	Vested	-61,273		2.24
	Granted	38,023		1.17
	Returned/Cancelled	-27,888		2.56
	Outstanding at December 31, 2013	43,776		2.87
	Vested	-99,381		2.51
	Granted	103,278		2.44
	Returned/Cancelled	-27,002		2.57
	Outstanding at December 31, 2014	20,671	$	2.83

Supplemental_Information_On_Oi1

Supplemental Information On Oil And Natural Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2014
Supplemental Information On Oil And Natural Gas Producing Activites [Abstract]
Schedule Of Capitalized Costs
		December 31,
		2014			2013
	Capitalized costs at the end of the period:⁽ᵃ⁾
	Oil and natrual gas properties and related equipment (successful efforts method)
	Property costs
	Proved property	$	649,432		$	636,816
	Unproved property		1,560			1,589
	Total property costs		650,992			638,405
	Materials and supplies		1,056			1,054
	Land		501			751
	Total		652,549			640,210
	Less: Accumulated depreciation, depletion, amortization and impairments		-517,239			-495,215
	Oil and natural gas properties and equipment, net	$	135,310		$	144,995
	(a)Capitalized costs include the cost of equipment and facilities for our oil and natural gas producing activities. Proved property costs include capitalized costs for leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); and support equipment. Unproved property costs include capitalized costs for oil and natural gas leaseholds where proved reserves do not exist.
Schedule Of Costs Incurred For Oil And Natural Gas Producing Activities
		For the year ended December 31,
		2014			2013
	Costs incurred for the period:
	Acquisition of properties
	Proved	$	1,239		$	20,012
	Unproved		112			209
	Development costs		5,865			15,694
	Oil and natural gas properties and equipment, net	$	7,216		$	35,915
Schedule Of Changes In Proved Developed And Undeveloped Reserves
								Natural Gas
		Total		Oil		Natural Gas		Liquids
		(Mmcfe)		(in Mmcfe)		(in Mmcfe)		(in Mmcfe)
	Net proved reserves
	31-Dec-12	92,982		6,503		-		86,479
	Extensions and discoveries	4,825		4,016		128		681
	Puchase of reserves in place	7,150		1,668		523		4,959
	Sales of reserves in place	-49,385		-		-		-49,385
	Revisions of previous estimates	44,727		1,147		207		43,373
	Production	-9,045		-901		-		-8,144
	31-Dec-13	91,254		12,433		858		77,963
	Extensions and discoveries	3,052		2,493		-		559
	Puchase of reserves in place	437		437		-		-
	Revisions of previous estimates	14,163		-3,542		-340		18,045
	Production	-9,143		-1,849		-169		-7,125
	31-Dec-14	99,763		9,972		349		89,442
	Proved developed reserves:
	31-Dec-13	78,629		11,170		858		66,601
	31-Dec-14	74,634		9,139		349		65,146
	Proved undeveloped reserves:
	31-Dec-13	12,625		1,264		-		11,361
	31-Dec-14	25,129		833		-		24,296
Summary Of Standardized Measure Of Estimated Discounted Future Cash Flows From Properties
			For the year ended December 31,
			2014			2013
	Future cash inflows		$	532,152		$	502,831
	Future production costs			-260,909			-227,315
	Future estimated development costs			-57,741			-40,694
	Future net cash flows			213,502			234,822
	10% annual discount for estimated timing of cash flows			-93,969			-91,108
	Standardized measure of discounted estimated future net cash
		flows related to proved gas reserves	$	119,533		$	143,714
Summary Of Change In Standardized Measure Of Estimated Discounted Future Net Cash Flows
			For the year ended December 31,
			2014			2013
	Beginning of the period		$	143,714		$	89,669
	Sales and transfers of oil and natural gas, net of production costs			-38,817			-21,244
	Net changes in prices and production costs related to future production			-18,410			50,425
	Development costs incurred during the period			18,075			5,615
	Changes in extensions and discoveries			24,611			28,494
	Revisions of previous quantity estimates			-22,034			21,455
	Purchases and sales of reserves in place			1,918			-2,297
	Accretion discount			14,371			8,967
	Other			-3,895			-37,370
	Standardized measure of discounted future net cash flows related to
		proved gas reserves	$	119,533		$	143,714

Recovered_Sheet1

Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	12 Months Ended		0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Aug. 09, 2013	Jun. 26, 2014
	customer	customer
Significant Accounting Policies [Line Items]
Amount paid for repurchased shares				$1,650,000
Percent of outstanding Sanchez L.P. common units	2.00%
Restricted cash held in escrow	1,700,000	1,700,000
Number of large customers	5	5
Deferred assets	0
Deferred liabilities	0
Allowance for doubtful accounts	200,000
Common Class B [Member]
Significant Accounting Policies [Line Items]
Restricted unvested common units granted and outstanding	100,825	380,327
Maximum [Member]
Significant Accounting Policies [Line Items]
Number of large customers	10
Allowance for doubtful accounts		$100,000
Sales [Member] | Customer One [Member]
Significant Accounting Policies [Line Items]
Percentage of sales revenue	33.00%	22.00%
Sales [Member] | Customer Two [Member]
Significant Accounting Policies [Line Items]
Percentage of sales revenue	30.00%	20.00%
Sales [Member] | Customer Three [Member]
Significant Accounting Policies [Line Items]
Percentage of sales revenue	16.00%	17.00%
Sales [Member] | Customer Four [Member]
Significant Accounting Policies [Line Items]
Percentage of sales revenue	14.00%	14.00%
Sales [Member] | Customer Five [Member]
Significant Accounting Policies [Line Items]
Percentage of sales revenue	7.00%	8.00%
Sanchez Energy Partners I [Member] | Common Class A [Member]
Significant Accounting Policies [Line Items]
Units owned by third party	484,505		1,130,512
Units owned by third party, percentage of total shares	100.00%
Sanchez Energy Partners I [Member] | Common Class B [Member]
Significant Accounting Policies [Line Items]
Units owned by third party	5,364,196		4,724,407
Units owned by third party, percentage of total shares	18.60%

Summary_Of_Significant_Account3

Summary Of Significant Accounting Policies (Schedule Of Weighted Average Units Outstanding) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Class Of Stock [Line Items]
Weighted average units outstanding during period - Basic	29,194,847	26,143,719
Weighted average units outstanding during period - Diluted	29,295,672	26,143,719
Common Class A [Member]
Class Of Stock [Line Items]
Weighted average units outstanding during period - Basic	763,261	933,613
Weighted average units outstanding during period - Diluted	763,261	933,613
Common Class B [Member]
Class Of Stock [Line Items]
Weighted average units outstanding during period - Basic	28,431,586	25,210,106
Weighted average units outstanding during period - Diluted	28,532,411	25,210,106

Summary_Of_Significant_Account4

Summary Of Significant Accounting Policies (Earnings Per Common Unit Amounts) (Details) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Class Of Stock [Line Items]
Income (loss) from continuing operations	$9,503	($25,857)
Distributions
Income (loss) from continuing operations	9,503	-25,857
Discontinued operations		-2,686
Net income (loss)	9,503	-28,543
Common Class A [Member]
Class Of Stock [Line Items]
Distributions
Income (loss) from continuing operations	190	-517
Discontinued operations		-53
Net income (loss)	190	-570
Basic and diluted loss from continuing operations per unit	$0.25	($0.55)
Basic and diluted loss from discontinued operations per unit		($0.06)
Basic and diluted earnings (loss) per unit	$0.25	($0.61)
Common Class B [Member]
Class Of Stock [Line Items]
Distributions
Income (loss) from continuing operations	9,313	-25,340
Discontinued operations		-2,633
Net income (loss)	$9,313	($27,973)
Basic and diluted loss from continuing operations per unit	$0.33	($1.01)
Basic and diluted loss from discontinued operations per unit		($0.10)
Basic and diluted earnings (loss) per unit	$0.33	($1.11)

Discontinued_Operations_Detail

Discontinued Operations (Details) (Robinson's Bend Field [Member], USD $)	0 Months Ended	3 Months Ended
In Millions, unless otherwise specified	Feb. 28, 2013	Mar. 31, 2013
Robinson's Bend Field [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of business	$63
Closing adjustment	4
Gain (Loss) on sale		($3.10)

Discontinued_Operations_Schedu

Discontinued Operations (Schedule Of Discontinued Operations) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Discontinued Operations [Abstract]
Revenues	$2,304
Loss from discontinued operations	($2,686)

Acquisitions_Narrative_Details

Acquisitions (Narrative) (Details) (USD $)	0 Months Ended		12 Months Ended
In Millions, except Share data, unless otherwise specified	Apr. 09, 2014	Aug. 09, 2013	Dec. 31, 2014
		item
Business Acquisition [Line Items]
Purchase price for acquisition	$1.40
Number of wells acquired	9
Percentage of wells acquired	20.00%
Sanchez Energy Partners I [Member]
Business Acquisition [Line Items]
Purchase price for acquisition		30.4
Cash received from acquisition		20.1
Amount borrowed from reserve based credit facility		$16.70
Number of wells acquired		67
Sanchez Energy Partners I [Member] | Common Class A [Member]
Business Acquisition [Line Items]
Units owned by third party		1,130,512	484,505
Sanchez Energy Partners I [Member] | Common Class B [Member]
Business Acquisition [Line Items]
Units owned by third party		4,724,407	5,364,196

Acquisitions_Estimated_Values_

Acquisitions (Estimated Values Of Assets Acquired And Liabilities Assumed) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Aug. 01, 2013
In Thousands, unless otherwise specified
Acquisitions [Abstract]
Oil and natural gas properties, equipment and facilities	$651,493	$639,156	$31,497
Asset retirement obligation	-17,031	-9,513	-1,088
Net assets acquired			$30,409

Acquisitions_Revenues_And_Leas

Acquisitions (Revenues And Lease Operating Expenses) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Revenues	$77,272	$44,077
Lease Operating Expenses	21,012	18,858
Sanchez Energy Partners I [Member]
Business Acquisition [Line Items]
Revenues		15,782
Lease Operating Expenses		$3,047

Acquisitions_Supplemental_Pro_

Acquisitions (Supplemental Pro Forma Information) (Details) (Sanchez Energy Partners I [Member], USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013
Business Acquisition [Line Items]
Revenue	$56,841
Loss from continuing operations	-18,514
Discontinued operations	-2,686
Net loss	($21,200)
Common Class A [Member]
Business Acquisition [Line Items]
Loss from continuing operations per unit - Basic and diluted	($0.23)
Discontinued operations per unit - Basic and diluted	($0.03)
Net loss per unit - Basic and diluted	($0.26)
Weighted average units outstanding - Basic and diluted	1,615,103
Common Class B [Member]
Business Acquisition [Line Items]
Loss from continuing operations per unit - Basic and diluted	($0.65)
Discontinued operations per unit - Basic and diluted	($0.09)
Net loss per unit - Basic and diluted	($0.74)
Weighted average units outstanding - Basic and diluted	28,057,592

Fair_Value_Measurements_Fair_V

Fair Value Measurements (Fair Value Of Assets And Liabilities On A Recurring Basis) (Details) (Recurring, USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Risk Mgmt Assets	$22,829	$10,602
Total Net Assets and Liabilities	22,829	10,602
Fair Value, Inputs, Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Risk Mgmt Assets	22,919	11,577
Risk Mgmt Liabilities	-90	-975
Total Net Assets and Liabilities	22,829	10,602
Netting Cash And Collateral [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Risk Mgmt Assets	-90	-975
Risk Mgmt Liabilities	$90	$975

Derivative_And_Financial_Instr2

Derivative And Financial Instruments (Narrative) (Details) (USD $)	1 Months Ended		3 Months Ended
In Millions, unless otherwise specified	31-May-13	Mar. 31, 2013	Mar. 31, 2014	Dec. 31, 2014
			bbl	item
Derivative [Line Items]
Number of counterparties				2
Cost to liquidate derivative hedge			$0.30
Number of barrels of oil			58,157
Execution of amendment			0.2
Reduction in outstanding interest rate swaps		30
Increase in interest rate swap settlement		2.1
Increase in natrual gas settlement	$0.30
Swaps Covering 2013 NYMEX
Derivative [Line Items]
Derivative swaps liquidated			395,218
Amount reduced from outstanding swap positions			1,041,814
Derivative contract swap, fixed price			3.66
Swaps Covering 2014 NYMEX
Derivative [Line Items]
Derivative swaps liquidated			1,634,530
2014 Oil Trade [Member]
Derivative [Line Items]
Stated swap price			98.1
2015 Oil Trade [Member]
Derivative [Line Items]
Stated swap price			93.5

Derivative_And_Financial_Instr3

Derivative And Financial Instruments (Summary Of Hedges In Place) (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2014
	bbl	MMBTU
Derivative [Line Items]
Volume (in Bbls)	58,157
NYMEX 2015 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in MMBtu)		1,215,420
Average Price		4.25
NYMEX 2015 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in MMBtu)		1,153,487
Average Price		4.25
NYMEX 2015 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in MMBtu)		1,096,023
Average Price		4.26
NYMEX 2015 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in MMBtu)		1,050,219
Average Price		4.26
NYMEX 2015 [Member]
Derivative [Line Items]
Volume (in MMBtu)		4,515,149
Average Price		4.26
NYMEX 2016 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in MMBtu)		1,010,633
Average Price		4.21
NYMEX 2016 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in MMBtu)		967,290
Average Price		4.21
NYMEX 2016 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in MMBtu)		923,541
Average Price		4.21
NYMEX 2016 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in MMBtu)		893,568
Average Price		4.22
NYMEX 2016 [Member]
Derivative [Line Items]
Volume (in MMBtu)		3,795,032
Average Price		4.21
NYMEX [Member]
Derivative [Line Items]
Volume (in MMBtu)		8,310,181
West Texas Intermediate 2015 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in Bbls)		69,479
Average Price		90.99
West Texas Intermediate 2015 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls)		66,183
Average Price		91.02
West Texas Intermediate 2015 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls)		63,025
Average Price		91.05
West Texas Intermediate 2015 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls)		60,143
Average Price		91.09
West Texas Intermediate 2015 [Member]
Derivative [Line Items]
Volume (in Bbls)		258,830
Average Price		91.04
West Texas Intermediate 2016 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in Bbls)		57,420
Average Price		85.64
West Texas Intermediate 2016 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls)		54,879
Average Price		85.64
West Texas Intermediate 2016 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls)		52,474
Average Price		85.64
West Texas Intermediate 2016 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls)		50,197
Average Price		85.64
West Texas Intermediate 2016 [Member]
Derivative [Line Items]
Volume (in Bbls)		214,970
Average Price		85.64
West Texas Intermediate [Member]
Derivative [Line Items]
Volume (in Bbls)		473,800

Derivative_And_Financial_Instr4

Derivative And Financial Instruments (Fair Value for Risk Management Assets and Liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivatives, Fair Value [Line Items]
Risk management assets-current	$14,671	$9,141
Risk management assets-non-current	8,158	1,461
Total gross assets	22,919	11,577
Total gross liabilities	-90	-975
Total net assets and liabilities	22,829	10,602
Risk Management Commodity [Member]
Derivatives, Fair Value [Line Items]
Risk management assets-current	14,698	10,043
Risk management assets-non-current	8,221	1,534
Risk management liabilities-current	-27	-903
Risk management liabilities-non-current	($63)	($72)

Derivative_And_Financial_Instr5

Derivative And Financial Instruments (Fair Value Applicable to Income Statement) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gains (losses) recognized in income	$19,854	($1,551)
Oil And Liquids Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gains (losses) recognized in income	19,854	-1,486
Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gains (losses) recognized in income		($65)

Debt_Details

Debt (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	6-May-14	Dec. 31, 2013	31-May-13	Apr. 30, 2013
Line of Credit Facility [Line Items]
Commitment fee on unutilized borrowing base	0.50%
Total net debt adjusted to EBITDA	3.50%
Cash interest expense adjusted to EBITDA	2.50%
Consolidated current asset ratio	1.00%
Actual debt ratio	1.6
Actual working capital ratio	5.6
Actual interest coverage ratio	13.3
Outstanding debt under reserve-based credit facility	$42,500,000		$50,700,000
Unamortized debt issue costs	700,000		800,000
Societe Generale [Member]
Line of Credit Facility [Line Items]
Reserve based credit facility maximum borrowing capacity		70,000,000		350,000,000
Maturity date of reserve-based credit facility	30-May-17
Borrowing base amount			55,000,000		37,500,000
Amount borrowed under credit facility	42,500,000
Commitment fee percentage	36.36%
OneWest Bank [Member]
Line of Credit Facility [Line Items]
Commitment fee percentage	36.36%
Bank of Oklahoma [Member]
Line of Credit Facility [Line Items]
Commitment fee percentage	27.28%
Letter of Credit [Member]
Line of Credit Facility [Line Items]
Reserve based credit facility maximum borrowing capacity	20,000,000
Amount borrowed under credit facility	0
Reserve Based Credit Facility [Member]
Line of Credit Facility [Line Items]
Borrowing base amount	70,000,000
Amount borrowed under credit facility			50,700,000
Outstanding debt on our reserve based credit facility	42,500,000
Remaining borrowing capacity	$27,500,000
Minimum [Member]
Line of Credit Facility [Line Items]
Exceeding of reserve-based credit facility over borrowing base	90.00%
Required working capital ratio	1
Required interest coverage ratio	2.5
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Interest rate	2.50%
Minimum [Member] | ABR [Member]
Line of Credit Facility [Line Items]
Interest rate	1.50%
Maximum [Member]
Line of Credit Facility [Line Items]
Hedging of projected monthly production	115.00%
Hedging of interest rate	90.00%
Required debt ratio	3.5
Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Interest rate	3.50%
Maximum [Member] | ABR [Member]
Line of Credit Facility [Line Items]
Interest rate	2.50%

Recovered_Sheet2

Oil and Natural Gas Properties (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Asset impairments	$5,424,000	$2,357,000
Gain (Loss) from sale of assets	-200,000
Exploration costs	0	0
Furniture, Fixtures And Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Useful life	1 year
Furniture, Fixtures And Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Useful life	7 years
Buildings
Property, Plant and Equipment [Line Items]
Useful life	20 years
Pipeline and Gathering Systems [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Useful life	25 years
Pipeline and Gathering Systems [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Useful life	40 years
Texas And Louisiana Oil And Natural Gas Fields [Member]
Property, Plant and Equipment [Line Items]
Non-cash impairment charges	5,400,000	2,200,000
Woodford Shale
Property, Plant and Equipment [Line Items]
Non-cash impairment charges		$100,000

Recovered_Sheet3

Oil and Natural Gas Properties (Oil and Natural Gas Properties) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Oil And Natural Gas Properties [Abstract]
Proved property	$649,432	$636,816
Unproved property	1,560	1,589
Total property costs	650,992	638,405
Materials and supplies	1,056	1,054
Land	501	751
Total	652,549	640,210
Less: Accumulated depreciation, depletion, amortization and impairments	-517,239	-495,215
Oil and natural gas properties and equipment, net	$135,310	$144,995

Oil_And_Natural_Gas_Properties2

Oil And Natural Gas Properties (Depletion, Depreciation, Amortization and Impairments) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Oil And Natural Gas Properties [Abstract]
DD&A of oil and natural gas-related assets	$17,533	$18,972
Asset impairments	5,424	2,357
Total	$22,957	$21,329

Benefit_Plans_Details

Benefit Plans (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Benefit Plans [Abstract]
Matching contributions made by employer	$0.20	$0.30

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	0 Months Ended		12 Months Ended	0 Months Ended
	Jul. 01, 2014	8-May-14	Dec. 31, 2014	Aug. 09, 2013
Related Party Transaction [Line Items]
Percent of value of properties held used to compute quarterly fee		0.38%
Administrative fee		$1,000,000
Administrative fee paid	500,000	500,000
Maximum asset acquisition, disposition and financing fee		2.00%
Term of Services Agreement			10 years
Term of Services Agreement renewal			10 years
Length of time after In-Service Date before Agreement can be terminated			24 months
Termination fee		5,000,000
Transaction value, percentage		5.00%
Termination costs			6,000,000
Shares issued in lieu of paying fee			59,562
Shares issued in lieu of paying fee, value			$165,582
Cost per share issued in lieu of paying fee			$2.78
Sanchez Oil And Gas Corporation [Member]
Related Party Transaction [Line Items]
Ownership percentage in company by related party			20.00%
Sanchez Energy Partners I [Member] | Common Class A [Member]
Related Party Transaction [Line Items]
Units owned by third party			484,505	1,130,512
Units owned by third party, percentage of total shares			100.00%
Sanchez Energy Partners I [Member] | Common Class B [Member]
Related Party Transaction [Line Items]
Units owned by third party			5,364,196	4,724,407
Units owned by third party, percentage of total shares			18.60%

Commitments_And_Contingencies_

Commitments And Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2006	Jun. 26, 2014	Apr. 10, 2014
Class Of Stock [Line Items]
Amount received from directors and officers insurance policy					$1,250,000
Quarterly dividend amount
Amount paid for repurchased shares				1,650,000
Constellation Energy Partners Management [Member]
Class Of Stock [Line Items]
Maximum backstop payment	5,000,000
CEPH [Member]
Class Of Stock [Line Items]
Proceeds from sales of shares			8,000,000
Quarterly dividend amount			333,333.33
Dividend payment period			6 years
Common Class A [Member]
Class Of Stock [Line Items]
Quarterly dividend amount
Common Class A [Member] | Constellation Energy Partners Management [Member]
Class Of Stock [Line Items]
Amount received from units transferred	800,000
Percentage of shares to be transferred	100.00%
Common Class B [Member]
Class Of Stock [Line Items]
Quarterly dividend amount
Common Class B [Member] | Constellation Energy Partners Management [Member]
Class Of Stock [Line Items]
Amount received from units transferred	1,000,000
Shares to be transferred	414,938
Settlement payment	$6,500,000

Asset_Retirement_Obligation_Na

Asset Retirement Obligation (Narrative) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Asset Retirement Obligation [Abstract]
Legally restricted assets	$0	$0

Asset_Retirement_Obligation_Re

Asset Retirement Obligation (Reconciliation of Asset Retirement Obligation) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation [Abstract]
Asset retirement obligation, beginning balance	$9,513	$7,665
Liabilities added from acquisitions	80	1,088
Liabilities added from drilling	59	244
Revisions to cost estimates	6,780
Settlements	-5	-3
Accretion expense	604	519
Asset retirement obligation, ending balance	$17,031	$9,513

UnitBased_Compensation_Narrati

Unit-Based Compensation (Narrative) (Details) (USD $)	12 Months Ended		0 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 18, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Non-cash compensation expense	$1.30	$1
Unrecognized portion of share based compensation expense	$0.10
Chief Executive Officer [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Notional units awarded			769,231
Chief Financial Officer [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Notional units awarded			256,410

UnitBased_Compensation_Schedul

Unit-Based Compensation (Schedule Of Units Granted) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
2009 Omnibus Incentive Compensation Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding	336,551
Number of Restricted Units, Vested	-1,481,073	-1,030,115
Number of Restricted Units, Granted	1,561,227	1,366,666
Number of Restricted Units, Outstanding	80,154	336,551
Long Term Incentive Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding	43,776
Number of Restricted Units, Vested	-402,339	-302,958
Number of Restricted Units, Granted	423,010	346,734
Number of Restricted Units, Outstanding	20,671	43,776
Restricted Stock Units (RSUs) [Member] | 2009 Omnibus Incentive Compensation Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding	336,551	666,778
Number of Restricted Units, Vested	-450,958	-370,363
Number of Restricted Units, Granted	346,403	184,313
Number of Restricted Units, Returned/Cancelled	-151,842	-144,177
Number of Restricted Units, Outstanding	80,154	336,551
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding	3.29	3.39
Weighted Averaged Grant Date Fair Value Per Unit, Vested	2.8	2.66
Weighted Averaged Grant Date Fair Value Per Unit, Granted	2.44	1.27
Weighted Averaged Grant Date Fair Value Per Unit, Reutrned/Cancelled	2.86	2.77
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding	3.18	3.29
Restricted Stock Units (RSUs) [Member] | Long Term Incentive Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding	43,776	94,914
Number of Restricted Units, Vested	-99,381	-61,273
Number of Restricted Units, Granted	103,278	38,023
Number of Restricted Units, Returned/Cancelled	-27,002	-27,888
Number of Restricted Units, Outstanding	20,671	43,776
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding	2.87	3.05
Weighted Averaged Grant Date Fair Value Per Unit, Vested	2.51	2.24
Weighted Averaged Grant Date Fair Value Per Unit, Granted	2.44	1.17
Weighted Averaged Grant Date Fair Value Per Unit, Reutrned/Cancelled	2.57	2.56
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding	2.83	2.87

Distributions_To_Unitholders_D

Distributions To Unitholders (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Distributions To Unitholders [Abstract]
Available cash balance	$0	$0

Members_Equity_Details

Members' Equity (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common units tendered for tax withholding purpose	160,182	139,810
Units tendered by employees for tax withholding, cost	($415)	($185)
Long Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested restricted common stock issued	20,671	43,776
Common units granted	423,010	346,734
Common units available under incentive plan	450,000	450,000
Common units vested	402,339	302,958
2009 Omnibus Incentive Compensation Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested restricted common stock issued	80,154	336,551
Common units granted	1,561,227	1,366,666
Common units available under incentive plan	1,650,000	1,650,000
Common units vested	1,481,073	1,030,115
Common Class A [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares units outstanding	484,505	1,615,017
Units tendered by employees for tax withholding, cost		-4
Common Class B [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares units outstanding	28,792,584	28,462,185
Units tendered by employees for tax withholding, cost	($415)	($181)

Supplemental_Information_On_Oi2

Supplemental Information On Oil And Natural Gas Producing Activities (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	Mcfe	Mcfe	Mcfe
Reserve Quantities [Line Items]
Exploration costs	$0	$0
Proved reserve estimates	99,763,000	91,254,000	92,982,000
Reserve revision	74,634,000	78,629,000
Increase (decrease) in proved reserve estimates	8,500,000	-1,700,000
Oil [Member]
Reserve Quantities [Line Items]
Proved reserve estimates	9,972,000	12,433,000	6,503,000
Reserve revision	9,139,000	11,170,000
Weighted-average product price	93.95	97.89
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Proved reserve estimates	89,442,000	77,963,000	86,479,000
Reserve revision	65,146,000	66,601,000
Weighted-average product price	35.11	41.21
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved reserve estimates	349,000	858,000
Reserve revision	349,000	858,000
Percentage of reserves	90.00%	85.00%
Weighted-average product price	4.09	3.706
Cherokee Basin [Member]
Reserve Quantities [Line Items]
Increase (decrease) in proved reserve estimates	12,900,000	4,800,000
Black Warrior Basin [Member]
Reserve Quantities [Line Items]
Reserve revision		44,800,000
Increase (decrease) in proved reserve estimates		-49,000,000
Sanchez Energy Partners I [Member]
Reserve Quantities [Line Items]
Increase (decrease) in proved reserve estimates		7,000,000

Supplemental_Information_On_Oi3

Supplemental Information On Oil And Natural Gas Producing Activities (Schedule Of Capitalized Costs) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Supplemental Information On Oil And Natural Gas Producing Activites [Abstract]
Proved property	$649,432	[1]	$636,816	[1]
Unproved property	1,560	[1]	1,589	[1]
Total property costs	650,992	[1]	638,405	[1]
Materials and supplies	1,056	[1]	1,054	[1]
Land	501	[1]	751	[1]
Total	652,549	[1]	640,210	[1]
Less: accumulated depreciation, depletion, amortization and impairments	-517,239	[1]	-495,215	[1]
Oil and natural gas properties and equipment, net	$135,310	[1]	$144,995	[1]
[1]	Capitalized costs include the cost of equipment and facilities for our oil and natural gas producing activities. Proved property costs include capitalized costs for leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); and support equipment. Unproved property costs include capitalized costs for oil and natural gas leaseholds where proved reserves do not exist.

Supplemental_Information_On_Oi4

Supplemental Information On Oil And Natural Gas Producing Activities (Schedule Of Costs Incurred For Oil And Natural Gas Producing Activities) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Supplemental Information On Oil And Natural Gas Producing Activites [Abstract]
Proved	$1,239	$20,012
Unproved	112	209
Development costs	5,865	15,694
Oil and natural gas properties and equipment, net	$7,216	$35,915

Supplemental_Information_On_Oi5

Supplemental Information On Oil And Natural Gas Producing Activities (Schedule Of Changes In Proved Developed And Undeveloped Reserves) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
	Mcfe	Mcfe
Reserve Quantities [Line Items]
Beginning balance	91,254,000	92,982,000
Extensions and discoveries	3,052,000	4,825,000
Purchase of reserves in place	437,000	7,150,000
Sales of reserves in place		-49,385,000
Revisions of previous estimates	14,163,000	44,727,000
Production	-9,143,000	-9,045,000
Ending balance	99,763,000	91,254,000
Proved developed reserves	74,634,000	78,629,000
Proved undeveloped reserves	25,129,000	12,625,000
Oil [Member]
Reserve Quantities [Line Items]
Beginning balance	12,433,000	6,503,000
Extensions and discoveries	2,493,000	4,016,000
Purchase of reserves in place	437,000	1,668,000
Revisions of previous estimates	-3,542,000	1,147,000
Production	-1,849,000	-901,000
Ending balance	9,972,000	12,433,000
Proved developed reserves	9,139,000	11,170,000
Proved undeveloped reserves	833,000	1,264,000
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning balance	858,000
Extensions and discoveries		128,000
Purchase of reserves in place		523,000
Revisions of previous estimates	-340,000	207,000
Production	-169,000
Ending balance	349,000	858,000
Proved developed reserves	349,000	858,000
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Beginning balance	77,963,000	86,479,000
Extensions and discoveries	559,000	681,000
Purchase of reserves in place		4,959,000
Sales of reserves in place		-49,385,000
Revisions of previous estimates	18,045,000	43,373,000
Production	-7,125,000	-8,144,000
Ending balance	89,442,000	77,963,000
Proved developed reserves	65,146,000	66,601,000
Proved undeveloped reserves	24,296,000	11,361,000

Supplemental_Information_On_Oi6

Supplemental Information On Oil And Natural Gas Producing Activities (Summary Of Standardized Measure Of Estimated Discounted Future Cash Flows From Properties) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Supplemental Information On Oil And Natural Gas Producing Activites [Abstract]
Future cash inflows	$532,152	$502,831
Future production costs	-260,909	-227,315
Future estimated development costs	-57,741	-40,694
Future net cash flows	213,502	234,822
10% annual discount for estimated timing of cash flows	-93,969	-91,108
Standardized measure of discounted estimated future net cash flows related to proved gas reserves	$119,533	$143,714

Supplemental_Information_On_Oi7

Supplemental Information On Oil And Natural Gas Producing Activities (Summary Of Change In Standardized Measure Of Estimated Discounted Future Net Cash Flows) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Supplemental Information On Oil And Natural Gas Producing Activites [Abstract]
Beginning of the period	$143,714	$89,669
Sales and transfers of oil and natural gas, net of production costs	-38,817	-21,244
Net changes in prices and production costs related to future production	-18,410	50,425
Development costs incurred during the period	18,075	5,615
Changes in extensions and discoveries	24,611	28,494
Revisions of previous quantity estimates	-22,034	21,455
Purchases and sales of reserves in place	1,918	-2,297
Accretion discount	14,371	8,967
Other	-3,895	-37,370
Standardized measure of discount future net cash flows related to proved gas reserves	$119,533	$143,714